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TABLE OF CONTENTS
INDEX TO FINANCIAL STATEMENTS

As filed with the Securities and Exchange Commission on July 23,August 27, 2010

Registration No. 333-166550

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



AMENDMENT NO. 34
TO

FORM S-1
REGISTRATION STATEMENT
UNDER
THE SECURITIES ACT OF 1933



Rhino Resource Partners LP
(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)
 27-2377517
(I.R.S. Employer
Identification Number)

424 Lewis Hargett Circle, Suite 250
Lexington, Kentucky 40503
(859) 389-6500

(Address, Including Zip Code, and Telephone Number, Including
Area Code, of Registrant's Principal Executive Offices)

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



Copies to:

Mike Rosenwasser
Brenda K. Lenahan

Vinson & Elkins L.L.P.
666 Fifth Avenue, 26th Floor
New York, New York 10103
Tel: (212) 237-0000
Fax: (212) 237-0100

 

Charles E. Carpenter
Sean T. Wheeler

Latham & Watkins LLP
885 Third Avenue
New York, New York 10022
Tel: (212) 906-1200
Fax: (212) 751-4864



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.


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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 becomes effective. This preliminary prospectus is not an offer to sell these securities and we are not soliciting an offer to buy these securities in any jurisdiction where the offer or sale is not permitted.

Subject to Completion, Dated July 23,August 27, 2010

PROSPECTUS

3,750,0003,244,000 Common Units

LOGO

Representing Limited Partner Interests

           This is our initial public offering. We are offering 3,750,0003,244,000 common units. We have been approved to list our common units on the New York Stock Exchange under the symbol "RNO."

           Prior to this offering, there has been no public market for our common units. We anticipate that the initial public offering price will be between $19.00 and $21.00 per common unit.

You should consider the risks which we have described in "Risk Factors" beginning on page 23 before buying our common units.

           These risks include the following:



           In order to comply with certain U.S. laws relating to the ownership of interests in mineral leases on federal lands, we require an owner of our units to be an "eligible citizen." If you are not an eligible citizen, your common units will be subject to redemption. Please read "The Partnership Agreement—Ineligible Citizens; Redemption."

 
 Per Common Unit Total 

Public offering price

 $  $  

Underwriting discount

 $  $  

Proceeds, before offering expenses, to us

 $  $  



           The underwriters may purchase up to an additional 562,500486,600 common units from us at the public offering price, less the underwriting discount, within 30 days from the date of this prospectus to cover over-allotments.

Neither the Securities and Exchange Commission nor any state securities commission has approved or disapproved of these securities or determined if this prospectus is truthful or complete. Any representation to the contrary is a criminal offense.

           The underwriters expect to deliver the common units to purchasers on or about                           , 2010.



RAYMOND JAMES

RBC CAPITAL MARKETS

STIFEL NICOLAUS WEISEL

The date of this prospectus is                           , 2010.


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MAPMAP

        The map above does not reflect our acquisition in August 2010 of certain mining assets located in Emery and Carbon Counties, Utah.


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TABLE OF CONTENTS

Summary

 1

Risk Factors

 23

Use of Proceeds

 5756

Capitalization

 5857

Dilution

 5958

Cash Distribution Policy and Restrictions on Distributions

 6160

Provisions of Our Partnership Agreement Relating to Cash Distributions

 77

Selected Historical Consolidated and Pro Forma Condensed Consolidated Financial and Operating Data

 94

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

 98

The Coal Industry

 134133

Business

 144143

Management

 189188

Executive Officer Compensation

 194

Security Ownership of Certain Beneficial Owners and Management

 210

Certain Relationships and Related Party Transactions

 211

Conflicts of Interest and Fiduciary Duties

 214

Description of the Common Units

 224

The Partnership Agreement

 227

Units Eligible for Future Sale

 244

Material Tax Consequences

 246

Investment in Rhino Resource Partners LP by Employee Benefit Plans

 269

Underwriting

 271

Validity of Our Common Units

 276

Experts

 276

Where You Can Find More Information

 277

Forward-Looking Statements

 277

Index to Financial Statements

 F-1

Appendix A—Form of First Amended and Restated Agreement of Limited Partnership of Rhino Resource Partners LP

 A-1

Appendix B—Application for Transfer of Common Units

 B-1

Appendix C—Glossary of Terms

 C-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 our common units means that information contained in this prospectus is correct after the date of this prospectus. This

i


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prospectus is not an offer to sell or solicitation of an offer to buy our common units in any circumstances under which the offer or solicitation is unlawful.



        Until                                         , 2010 (25 days after the date of this prospectus), all dealers that buy, sell or trade our common units, 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.

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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 units. The information presented in this prospectus assumes that the underwriters' option to purchase additional common units is not exercised unless otherwise noted. You should read "Risk Factors" beginning on page 23 for information about important risks that you should consider before buying our common units.

        References in this prospectus to "Rhino Resource Partners LP," "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 Resource Partners LP in connection with this offering, except that, unless otherwise specified, references to our proven and probable reserves, non-reserve coal deposits and coal production do not include the reserves and deposits owned by or the production of Rhino Eastern LLC, a joint venture in which we have a 51% membership interest and for which we serve as manager. When used in the present tense or prospectively, those terms refer to Rhino Resource Partners LP and its subsidiaries. References in this prospectus to "Wexford" refer to Wexford Capital LP, our sponsor, and its affiliates and principals. We include a glossary of some of the terms used in this prospectus as Appendix C.

Rhino Resource Partners LP

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

        Our primary business objective is to make quarterly cash distributions to our unitholders at our minimum quarterly distribution and, over time, increase our quarterly cash distributions. Initially, we will pay our common unitholders distributions of $0.445 per common unit per quarter, or $1.78 per common unit annually, to the extent we have sufficient cash from our operations after establishment of cash reserves and payment of fees and expenses, including payments to our general partner and its affiliates, before we pay any distributions to our subordinated unitholders.

        For the year ended December 31, 2009, we generated revenues of approximately $419.8 million and net income of approximately $19.5 million. For the threesix months ended March 31,June 30, 2010, we generated revenues of approximately $66.6$145.0 million and net income of approximately $6.5$13.7 million. As of July 13,August 23, 2010, we had sales commitments for approximately 99%97% and 80%69% of our estimated coal production (including purchased coal to supplement production and excluding results from the joint venture) for the year ending December 31, 2010 and the twelve months ending JuneSeptember 30, 2011, respectively.


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Our Properties

        We have a geographically diverse asset base with coal reserves located in Central Appalachia, Northern Appalachia, the Illinois Basin and the Western Bituminous region. As of March 31, 2010, we controlled an estimated 285.4 million tons of proven and probable coal reserves, consisting of an estimated 272.9 million tons of steam coal and an estimated 12.5 million tons of metallurgical coal. In addition, as of March 31, 2010, we controlled an estimated 122.2 million tons of non-reserve coal deposits. As of March 31, 2010, Rhino Eastern LLC, a joint venture in which we have a 51% membership interest and for which we serve as manager, controlled an estimated 22.4 million tons of proven and probable coal reserves at the Rhino Eastern mining complex located in Central Appalachia, consisting entirely of premium mid-vol and low-vol metallurgical coal, and an estimated 34.3 million tons of non-reserve coal deposits. Our and the joint venture's proven and probable coal reserves and non-reserve coal deposits were the same in all material respects as of December 31, 2009. We currently operate twelveeleven mines, including sevensix underground and five surface mines, located in Kentucky, Ohio, Colorado and West Virginia. In addition, our joint venture currently operates one underground mine in West Virginia. The number of mines that we operate may vary from time to time depending on a number of factors, including the existing demand for and price of coal, depletion of economically recoverable reserves and availability of experienced labor. Excluding results from the joint venture, for the year ended December 31, 2009, we produced approximately 4.7 million tons of coal, purchased approximately 2.0 million tons of coal and sold approximately 6.7 million tons of coal, approximately 99% of which were pursuant to supply contracts. Excluding results from the joint venture, for the threesix months ended March 31,June 30, 2010, we produced approximately 1.02.1 million tons of coal and sold approximately 0.92.0 million tons of coal, approximately 99%97% of which were pursuant to supply contracts. Additionally, the joint venture produced and sold approximately 0.2 million tons and approximately 0.1 million tons of premium mid-vol metallurgical coal for the year ended December 31, 2009 and the threesix months ended March 31,June 30, 2010, respectively.

        Since our predecessor's formation in 2003, we have significantly grown our coal reserves. Since April 2003, we have completed numerous coal asset acquisitions with a total purchase price of approximately $208.3 million. Through these acquisitions and coal lease transactions, we have substantially increased$223.3 million, including our proven and probable coal reserves and non-reserve coal deposits. We expect to complete the acquisition in August 2010 of certain mining assets of C.W. Mining Company out of bankruptcy for approximately $15.0 million.bankruptcy. The assets to be acquired are located in Emery and Carbon Counties, Utah and include coal reserves and non-reserve coal deposits, underground mining equipment and infrastructure, an overland belt conveyor system, a loading facility and support facilities. We intend to fund the asset acquisition with borrowings underThrough these acquisitions and coal lease transactions, we have substantially increased our credit agreement.proven and probable coal reserves and non-reserve coal deposits.

        In addition, we have successfully grown our production through internal development projects. Between 2004 and 2006, we invested approximately $19.0 million in the Hopedale mine located in Northern Appalachia to develop the estimated 18.5 million tons of proven and probable coal reserves at the mine. The Hopedale mine produced approximately 1.5 million tons of coal for the year ended December 31, 2009 and approximately 0.30.7 million tons of coal for the threesix months ended March 31,June 30, 2010. In 2007, we completed initial development of Mine 28, a new underground high-vol metallurgical coal mine at the Rob Fork mining complex located in Central Appalachia. We finished additional development work on Mine 28 in 2009, which completes all major foreseen development projects for the life of these reserves. Mine 28 produced approximately 0.4 million tons of metallurgical coal for the year ended December 31, 2009 and approximately 0.10.2 million tons of metallurgical coal for the threesix months ended March 31,June 30, 2010. As of March 31, 2010, we also controlled or managed a significant amount of


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undeveloped proven and probable coal reserves. These reserves can be developed and produced over time as


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industry and regional conditions permit. We believe our existing asset base will continue to provide attractive internal growth projects.

        The following table summarizes our and the joint venture's mining complexes, production and reserves by region:



  
 Production for the (2) Proven and Probable Reserves
as of March 31, 2010 (3)
 
  
 Production for the (2) Proven and Probable Reserves
as of March 31, 2010 (3)
 


 Type of
Production (1)
 Year Ended
December 31, 2009
 Three Months
Ended
March 31, 2010
 
 Type of
Production (1)
 Year Ended
December 31, 2009
 Six Months
Ended
June 30, 2010
 
RegionRegion Total Steam Metallurgical Region Total Steam Metallurgical 


  
 (in million tons)
 
  
 (in million tons)
 

Central Appalachia

Central Appalachia

  

Central Appalachia

  

Tug River Complex (KY, WV)

Tug River Complex (KY, WV)

 

U, S

 
0.5
 
0.1
 
34.8
 
28.8
 
6.0
 

Tug River Complex (KY, WV)

 

U, S

 
0.5
 
0.2
 
34.8
 
28.8
 
6.0
 

Rob Fork Complex (KY)

Rob Fork Complex (KY)

 

U, S

 
1.2
 
0.3
 
26.2
 
19.7
 
6.5
 

Rob Fork Complex (KY)

 

U, S

 
1.2
 
0.5
 
26.2
 
19.7
 
6.5
 

Deane Complex (KY)

Deane Complex (KY)

 

U

 
0.6
 
0.1
 
40.8
 
40.8
 
 

Deane Complex (KY)

 

U

 
0.6
 
0.2
 
40.8
 
40.8
 
 

Northern Appalachia

Northern Appalachia

  

Northern Appalachia

  

Hopedale Complex (OH)

Hopedale Complex (OH)

 

U

 
1.5
 
0.3
 
18.5
 
18.5
 
 

Hopedale Complex (OH)

 

U

 
1.5
 
0.7
 
18.5
 
18.5
 
 

Sands Hill Complex (OH)

Sands Hill Complex (OH)

 

S

 
0.7
 
0.2
 
8.6
 
8.6
 
 

Sands Hill Complex (OH)

 

S

 
0.7
 
0.3
 
8.6
 
8.6
 
 

Leesville Field (OH)

Leesville Field (OH)

 

U

 
 
 
26.8
 
26.8
 
 

Leesville Field (OH)

 

U

 
 
 
26.8
 
26.8
 
 

Springdale Field (PA)

Springdale Field (PA)

 

U

 
 
 
13.8
 
13.8
 
 

Springdale Field (PA)

 

U

 
 
 
13.8
 
13.8
 
 

Illinois Basin

Illinois Basin

  

Illinois Basin

  

Taylorville Field (IL)

Taylorville Field (IL)

 

U

 
 
 
109.5
 
109.5
 
 

Taylorville Field (IL)

 

U

 
 
 
109.5
 
109.5
 
 

Western Bituminous

Western Bituminous

  

Western Bituminous

  

McClane Canyon Mine (CO)

McClane Canyon Mine (CO)

 

U

 
0.3
 
0.1
 
6.4
 
6.4
 
 

McClane Canyon Mine (CO)

 

U

 
0.3
 
0.1
 
6.4
 
6.4
 
 
                         

Total

   
4.7
 
1.0
 
285.4
 
272.9
 
12.5
 

Total

   
4.7
 
2.1
 
285.4
 
272.9
 
12.5
 
                         

Central Appalachia

Central Appalachia

  

Central Appalachia

  

Rhino Eastern Complex (WV) (4)

Rhino Eastern Complex (WV) (4)

 

U

 
0.2
 
0.1
 
22.4
 
 
22.4
 

Rhino Eastern Complex (WV) (4)

 

U

 
0.2
 
0.1
 
22.4
 
 
22.4
 

(1)
Indicates mining methods that could be employed at each complex and does not necessarily reflect current methods of production. U=underground; S=surface.
(2)
Total production based on actual amounts and not the rounded amounts shown in this table.
(3)
Represents recoverable tons.
(4)
Owned by a joint venture in which we have a 51% membership interest and for which we serve as manager. Amounts shown include 100% of the reserves and production.


Our Business Strategy

        Our principal business strategy is to safely, efficiently and profitably produce and sell both steam and metallurgical coal from our diverse asset base in order to maintain and, over time, increase our quarterly cash distributions. Our plan for executing this strategy includes the following key components:


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Our Competitive Strengths

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

        For a more detailed description of our business strategies and competitive strengths, please read "Business—Our Business Strategy" and "—Our Competitive Strengths."


Recent Financial Performance

        Our consolidated financial statements forcovering the three monthsone month ended and six months ended June 30,July 31, 2010 are not prepared yet.yet prepared. Our expectations with respect to our results for the periods discussed belowthat period are based upon management estimates. Our actual results may differ from these estimates.

We expect to reportgenerate total revenues and net income for the threeone month ended July 31, 2010 that are similar to our average monthly total revenues and net income during the six months ended June 30, 2010 that were slightly higher than for the three months ended March 31, 2010, due to slight increases in total coal sales volumes and coal prices. We expect that our costs of operations have increased slightly as a result of an increase in purchased coal costs, which we incurred in order to2010.


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supplement production while transitioning underground operations in Central Appalachia to better enable us to take advantage of favorable pricing for metallurgical coal. Nonetheless, we expect that our increased revenues will offset our increased costs, resulting in greater net income for three months ended June 30, 2010 than for the three months ended March 31, 2010.

Risk Factors

        An investment in our common units involves risks. You should carefully consider the following risk factors, those other risks described in "Risk Factors" and the other information in this prospectus, before deciding whether to invest in our common units. The following risks are discussed in more detail in "Risk Factors" beginning on page 23.


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Our Management

        We are managed and operated by the board of directors and executive officers of our general partner, Rhino GP LLC. Following this offering, approximately 69.8%73.8% of our outstanding common units and all of our outstanding subordinated units and incentive distribution rights will be owned by Wexford. As a result of owning our general partner, Wexford will have the right to appoint all members of the board of directors of our general partner, including the independent directors. Our unitholders will not be entitled to elect our general partner or its directors or otherwise directly participate in our management or operation. For more information about the executive officers and directors of our general partner, please read "Management."

        Following the consummation of this offering, neither our general partner nor Wexford will receive any management fee or other compensation in connection with our general partner's management of our business, but webusiness. Our general partner, however, may receive incentive fees resulting from holding the incentive distribution rights. Please see "Provisions of our Partnership Agreement Relating to Cash Distributions—Distributions of Available Cash—General Partner Interest and Incentive Distribution Rights." We will reimburse our general partner and its affiliates, including Wexford, for all expenses they incur and payments they make on our behalf. Our partnership agreement does not set a limit on the amount of expenses for which our general partner and its affiliates may be reimbursed. These expenses include salary, bonus, incentive compensation and other amounts paid to persons who perform services for us or on our behalf and expenses allocated to our general partner by its affiliates. Our partnership agreement provides that our general partner will determine in good faith the expenses that are allocable to us.

        In order to maximize operational flexibility, our operations will be conducted through, and our operating assets will be owned by, our wholly owned subsidiary, Rhino Energy LLC, and its subsidiaries. Rhino Resource Partners LP does not have any employees. All of the employees that conduct our business are employed by our general partner or our subsidiaries.

        Wexford Capital LP, or Wexford Capital, is a Securities and Exchange Commission, or SEC, registered investment advisor. Wexford Capital, which was formed in 1994, manages a series of investment funds and has over $6.0 billion of assets under management.


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Conflicts of Interest and Fiduciary Duties

        Our general partner has a legal duty to manage us in a manner beneficial to holders of our common and subordinated units. This legal duty is commonly referred to as a "fiduciary duty." However, the officers and directors of our general partner also have fiduciary duties to manage our general partner in a manner beneficial to Wexford. As a result, conflicts of interest may arise in the future between us and our unitholders, on the one hand, and Wexford and our general partner, on the other hand.

        Delaware law provides that Delaware limited partnerships may, in their partnership agreements, restrict or expand the fiduciary duties owed by the general partner to limited partners and the partnership. Our partnership agreement limits the liability of, and reduces the fiduciary duties owed by, our general partner to our common unitholders. Our partnership agreement also restricts the remedies available to our unitholders for actions that might otherwise constitute a breach of fiduciary duty by our general partner. By purchasing a common unit, a unitholder is treated as having consented to various actions and potential conflicts of interest contemplated in the partnership agreement that might otherwise be considered a breach of fiduciary or other duties under applicable state law.

        For a more detailed description of the conflicts of interest and the fiduciary duties of our general partner, please read "Conflicts of Interest and Fiduciary Duties." For a description of other relationships with our affiliates, please read "Certain Relationships and Related Party Transactions."


Principal Executive Offices

        Our principal executive offices are located at 424 Lewis Hargett Circle, Suite 250, Lexington, Kentucky. Our phone number is (859) 389-6500. Our website address will behttp://rhinolp.com. We intend 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.


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The Transactions

        We are a Delaware limited partnership formed in April 2010 by Wexford to own and operate the business that has historically been conducted by Rhino Energy LLC.

        In connection with the closing of this offering, the following will occur:


(1)
Assumes the underwriters do not exercise their option to purchase additional common units. If the underwriters do not exercise their option to purchase additional common units, we will issue an additional 562,500486,600 common units to Rhino Energy Holdings LLC at the expiration of the option. If the underwriters exercise their option to purchase up to 562,500486,600 additional common units, the number of common units purchased by the underwriters pursuant to such exercise will be sold to the public instead of being issued to Rhino Energy Holdings LLC. The net proceeds from any exercise of the underwriters' option to purchase additional common units (approximately $10.5$9.1 million based on an assumed initial offering price of $20.00 per common unit, if exercised in full, after deducting the estimated underwriting discount and offering expenses payable by us) will be used to reimburse Rhino Energy Holdings LLC for capital expenditures it incurred with respect to the assets contributed to us.


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Organizational Structure

        The following is a simplified diagram of our ownership structure before this offering.

GRAPHIC


(1)
Represents investment funds managed by, and principals of, Wexford Capital. Please read "Certain Relationships and Related Party Transactions—Ownership Interests of Certain Directors of Our General Partner" for additional information.

(2)
Includes a joint venture in which Rhino Energy LLC indirectly owns a 51% membership interest.

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        The following is a simplified diagram of our ownership structure after giving effect to this offering and the related transactions.

Public Common Units

  14.812.8%

Interests of Wexford:

    
 

Common Units

  34.236.2%
 

Subordinated Units

  49.0%
 

General Partner Interest

  2.0%
    

  100.0%
    

GRAPHICGRAPHIC


(1)
Represents investment funds managed by, and principals of, Wexford Capital. Please read "Security Ownership of Certain Beneficial Owners and Management" and "Certain Relationships and Related Party Transactions—Ownership Interests of Certain Directors of Our General Partner" for additional information.

(2)
Includes a joint venture in which Rhino Energy LLC owns a 51% membership interest.

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The Offering

Common units offered to the public 3,750,0003,244,000 common units.

 

 

4,312,5003,730,600 common units if the underwriters exercise their option to purchase additional common units in full.

Units outstanding after this offering

 

12,397,000 common units and 12,397,000 subordinated units, each representing a 49.0% limited partner interest in us. If the underwriters do not exercise their option to purchase additional common units, we will issue 562,500486,600 common units to Rhino Energy Holdings LLC at the expiration of the 30-day option period. If, and to the extent, the underwriters exercise their option to purchase additional common units, the number of units purchased by the underwriters pursuant to such exercise will be sold to the public, and any of the 562,500486,600 common units not purchased by the underwriters pursuant to the option will be issued to Rhino Energy Holdings LLC as part of our formation transactions. Accordingly, the exercise of the underwriters' option will not affect the total number of units outstanding or the amount of cash needed to pay the minimum quarterly distribution on all units. Our general partner will own a 2.0% general partner interest in us.

Use of proceeds

 

We intend to use the estimated net proceeds of approximately $67.0$57.5 million from this offering (based on an assumed initial offering price of $20.00 per common unit), after deducting the estimated underwriting discount and offering expenses, and the related contribution by our general partner of approximately $10.1 million (based on an assumed initial offering price of $20.00 per common unit) to maintain its 2.0% general partner interest in us, to repay indebtedness outstanding under our credit agreement. Upon application of the net proceeds from this offering as described herein,and the related capital contribution by our general partner, we will have $50.1$34.5 million of indebtedness outstanding under our credit agreement.

 

 

The net proceeds from any exercise of the underwriters' option to purchase additional common units (approximately $10.5$9.1 million based on an assumed initial offering price of $20.00 per common unit, if exercised in full, after deducting the estimated underwriting discount)full) will be used to reimburse Wexford for capital expenditures incurred with respect to the assets contributed to us.

 

 

Please read "Use of Proceeds."

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Cash distributions We will make a minimum quarterly distribution of $0.445 per common unit (or $1.78 per common unit on an annualized basis) to the extent we have sufficient cash from operations after establishment of cash reserves and payment of costs and expenses, including reimbursement of expenses to our general partner and its affiliates. These expenses include salary, bonus, incentive compensation and other amounts paid to persons who perform services for us or on our behalf and expenses allocated to our general partner by its affiliates. Our partnership agreement does not set a limit on the amount of cash reserves that our general partner may establish or the amount of expenses for which our general partner and its affiliates may be reimbursed. Our ability to pay cash distributions at the minimum quarterly distribution rate is subject to various restrictions and other factors described in more detail under "Cash Distribution Policy and Restrictions on Distributions."

 

 

For the first quarter that we are publicly traded, we will pay investors in this offering a prorated distribution covering the period from the completion of this offering through September 30, 2010, based on the actual length of that period.

 

 

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

 

•       first, 98.0% to the holders of common units and 2.0% to our general partner, until each common unit has received the minimum quarterly distribution of $0.445 plus any arrearages from prior quarters;

 

•       second, 98.0% to the holders of subordinated units and 2.0% to our general partner, until each subordinated unit has received the minimum quarterly distribution of $0.445; and

 

•       third, 98.0% to all unitholders, pro rata, and 2.0% to our general partner, until each unit has received a distribution of $0.51175.


 

 

If cash distributions to our unitholders exceed $0.51175 per unit in any quarter, our unitholders and our general partner will receive distributions according to the following percentage allocations:

 

  
 Marginal Percentage
Interest in
Distributions
 
 Total Quarterly Distribution
  
 General
Partner
 
 Target Amount Unitholders 
 

above $0.51175 up to $0.55625

  85.0% 15.0%
 

above $0.55625 up to $0.6675

  75.0% 25.0%
 

above $0.6675

  50.0% 50.0%

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  The percentage interests shown for our general partner include its 2.0% general partner interest. We refer to the additional increasing distributions to our general partner as "incentive distributions." We view these distributions as an incentive fee providing our general partner with a direct financial incentive to expand the profitability of our business to enable us to increase distributions to our limited partners. Please read "Provisions of Our Partnership Agreement Relating to Cash Distributions—Distributions of Available Cash—General Partner Interest and Incentive Distribution Rights."

 

 

Pro forma cash available for distribution generated during the year ended December 31, 2009 and the twelve months ended March 31,June 30, 2010 was approximately $33.4 million and $39.3$43.6 million, respectively. The amount of available cash we need to pay the minimum quarterly distribution for four quarters on our common units and subordinated units to be outstanding immediately after this offering and the corresponding distribution on our general partner interest is approximately $45.0 million (or an average of approximately $11.3 million per quarter). As a result, for the year ended December 31, 2009 and the twelve months ended March 31,June 30, 2010 we would have generated available cash sufficient to pay 100% of the minimum quarterly distribution on all of our common units, but only approximately 48.3%48.4% and 74.8%93.5%, respectively, of the minimum quarterly distribution on our subordinated units during those periods. We have not usedcalculated available cash on a quarter-by-quarter estimatesbasis for each quarter in the year ended December 31, 2009 andor the twelve months ended March 31,June 30, 2010 to determine if we would have generated available cash sufficient to pay the minimum quarterly distribution for each quarter during those periods. Please read "Cash Distribution Policy and Restrictions on Distributions—Pro Forma and Forecasted Results of Operations and Cash Available for Distribution."

 

 

We believe, based on our financial forecast and related assumptions included in "Cash Distribution Policy and Restrictions on Distributions—Pro Forma and Forecasted Results of Operations and Cash Available for Distribution," that we will have sufficient available cash to pay the minimum quarterly distribution of $0.445 on all of our units and the corresponding distribution on our general partner's 2.0% interest for each quarter in the twelve months ending JuneSeptember 30, 2011. Please read "Cash Distribution Policy and Restrictions on Distributions."

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Subordinated units Wexford will initially own all of our subordinated units. The principal difference between our common and subordinated units is that in any quarter during the subordination period, the subordinated units will not be entitled to receive any distribution until the common units have received the minimum quarterly distribution plus any arrearages in the payment of the minimum quarterly distribution from prior quarters. Subordinated units will not accrue arrearages.

Conversion of subordinated units

 

The subordination period will end on the first business day after we have earned and paid at least (1) $1.78 (the minimum quarterly distribution on an annualized basis) on each outstanding unit and the corresponding distribution on our general partner's 2.0% interest for each of three consecutive, non-overlapping four quarter periods ending on or after JuneSeptember 30, 2013 or (2) $2.67 (150.0% of the annualized minimum quarterly distribution) on each outstanding unit and the corresponding distributions on our general partner's 2.0% interest and the related distribution on the incentive distribution rights for the four-quarter period immediately preceding that date.

 

 

The subordination period also will end upon the removal of our general partner other than for cause if no subordinated units or common units held by the holders of subordinated units or their affiliates are voted in favor of that removal.

 

 

When the subordination period ends, all subordinated units will convert into common units on a one-for-one basis, and all common units thereafter will no longer be entitled to arrearages. Please read "Provisions of Our Partnership Agreement Relating to Cash Distributions—Subordination Period."

Ineligible citizens and
redemption

 

Only eligible citizens (meaning a person or entity qualified to hold an interest in mineral leases on federal lands) will be entitled to receive distributions or be allocated income or loss from us. If a transferee or a unitholder, as the case may be, does not properly complete the transfer application or any required recertification, for any reason, the transferee or unitholder will have no right to vote its units on any matter and we have the right to redeem such units at a price which is equal to the lower of the transferee's or unitholder's purchase price or the then-current market price of such units. The redemption price will be paid in cash or by delivery of a promissory note, as determined by our general partner. Please read "Description of the Common Units—Transfer of Common Units" and "The Partnership Agreement—Ineligible Citizens; Redemption."

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General partner's right to reset the target distribution levels Our general partner, as the initial holder of our incentive distribution rights, has the right, at any time when there are no subordinated units outstanding and it has received incentive distributions at the highest level to which it is entitled (48.0%, in addition to distributions paid on its 2.0% general partner interest) for each of the prior four consecutive fiscal quarters, to reset the initial target distribution levels at higher levels based on our cash distributions at the time of the exercise of the reset election. If our general partner transfers all or a portion of our incentive distribution rights in the future, then the holder or holders of a majority of our incentive distribution rights will be entitled to exercise this right. The following assumes that our general partner holds all of the incentive distribution rights at the time that a reset election is made. Following a reset election, the minimum quarterly distribution will be adjusted to equal the reset minimum quarterly distribution, and the target distribution levels will be reset to correspondingly higher levels based on the same percentage increases above the reset minimum quarterly distribution.

 

 

If our general partner elects to reset the target distribution levels, it will be entitled to receive common units and to retain its then-current general partner interest. The number of common units to be issued to our general partner will equal the number of common units which would have entitled the holder to an average aggregate quarterly cash distribution in the prior two quarters equal to the average of the distributions to our general partner on the incentive distribution rights in the prior two quarters. Please read "Provisions of Our Partnership Agreement Relating to Cash Distributions—General Partner's Right to Reset Incentive Distribution Levels."

Issuance of additional units

 

Our partnership agreement authorizes us to issue an unlimited number of additional units without the approval of our unitholders. Please read "Units Eligible for Future Sale" and "The Partnership Agreement—Issuance of Additional Interests."

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Limited voting rights Our general partner will manage and operate us. Unlike the holders of common stock in a corporation, our unitholders will have only limited voting rights on matters affecting our business. Our unitholders will have no right to elect our general partner or its directors on an annual or other continuing basis. Our general partner may not be removed except by a vote of the holders of at least 662/3% of the outstanding units, including any units owned by our general partner and its affiliates, voting together as a single class. Upon consummation of this offering, Wexford will own an aggregate of 84.9%86.9% of our common and subordinated units (or 82.6%85.0% of our common and subordinated units, if the underwriters exercise their option to purchase additional common units in full). This will give Wexford the ability to prevent the removal of our general partner. Please read "The Partnership Agreement—Voting Rights."

Limited call right

 

If at any time our general partner and its affiliates own more than 90% of the outstanding common units, our general partner has the right, but not the obligation, to purchase all of the remaining common units at a price equal to the greater of (1) the average of the daily closing price of the common units over the 20 trading days preceding the date three days before notice of exercise of the call right is first mailed and (2) the highest per-unit price paid by our general partner or any of its affiliates for common units during the 90-day period preceding the date such notice is first mailed. If our general partner and its affiliates reduce their ownership percentage to below 70% of the outstanding common units, the ownership threshold to exercise the limited call right will be reduced to 80%. Please read "The Partnership Agreement—Limited Call Right."

Estimated ratio of taxable income to distributions

 

We estimate that if you own the common units you purchase in this offering through the record date for distributions for the period ending December 31, 2012, you will be allocated, on a cumulative basis, an amount of federal taxable income for that period that will be approximately 40.0% of the cash distributed to you with respect to that period. For example, if you receive an annual distribution of $1.78 per unit, we estimate that your average allocable federal taxable income per year will be no more than approximately $0.72 per unit. Thereafter, the ratio of allocable taxable income to cash distributions to you could substantially increase. Please read "Material Tax Consequences—Tax Consequences of Unit Ownership—Ratio of Taxable Income to Distributions" for the basis of this estimate.

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Material federal income tax consequences For a discussion of the material federal income tax consequences that may be relevant to prospective unitholders who are individual citizens or residents of the United States, please read "Material Tax Consequences."

Exchange listing

 

We have been approved to list our common units on the New York Stock Exchange, or NYSE, under the symbol "RNO."

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Summary Historical Consolidated and Condensed Consolidated and Pro Forma Condensed 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 December 31, 2007 is derived from the audited historical consolidated statement of financial position of Rhino Energy LLC that is not included in this prospectus. The summary historical consolidated financial data presented as of December 31, 2008 and 2009 and for the years ended December 31, 2007, 2008 and 2009 is derived from the audited historical consolidated financial statements of Rhino Energy LLC that are included elsewhere in this prospectus. The historical consolidated financial data as of and for the year ended December 31, 2008 was restated to reflect certain selling, general and administrative expenses within the statement of operations, rather than as a distribution to members in the statement of financial position. The summary historical consolidated financial data presented as of March 31,June 30, 2010 and for the threesix months ended March 31,June 30, 2009 and 2010 is derived from the unaudited historical condensed consolidated financial statements of Rhino Energy LLC that are included elsewhere in this prospectus. The summary historical condensed consolidated financial data presented as of March 31,June 30, 2009 is derived from our predecessor's accounting records, which are unaudited.

        The summary pro forma condensed consolidated financial data presented for the year ended December 31, 2009 and as of and for the threesix months ended March 31,June 30, 2010 is derived from our unaudited pro forma condensed consolidated financial statements included elsewhere in this prospectus. Our unaudited pro forma condensed consolidated financial statements give pro forma effect to:

        The unaudited pro forma condensed consolidated statement of financial position assumes the items listed above occurred as of March 31,June 30, 2010. The unaudited pro forma condensed consolidated statements of operations data for the year ended December 31, 2009 and for the threesix months ended March 31,June 30, 2010 assume the items listed above occurred as of January 1, 2009. 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 partnership.

        For a detailed discussion of the summary historical consolidated financial information contained in 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" and the audited historical consolidated financial statements of Rhino Energy LLC and our unaudited pro forma condensed consolidated financial statements included elsewhere in this prospectus. Among other things,


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the historical consolidated and unaudited pro forma condensed consolidated financial


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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 represents net income before interest expense, income taxes and depreciation, depletion and amortization. This measure is not calculated or presented in accordance with generally accepted accounting principles, or GAAP. We explain this measure under"—Non-GAAP Financial Measure" and reconcile it to its most directly comparable financial measures calculated and presented in accordance with GAAP.



 Rhino Energy LLC Historical  
  
 
 Rhino Energy LLC Historical  
  
 


 Consolidated Condensed
Consolidated
 Rhino Resource Partners LP
Pro Forma Condensed
Consolidated
 
 Consolidated Condensed
Consolidated
 Rhino Resource Partners LP
Pro Forma Condensed
Consolidated
 


 Year Ended December 31, Three Months
Ended
March 31,
 Year Ended
December 31,
 Three Months
Ended
March 31,
 
 Year Ended December 31, Six Months
Ended
June 30,
 Year Ended
December 31,
 Six Months
Ended
June 30,
 


  
 2008
(as restated)
  
 
  
 2008
(as restated)
  
 


 2007 2009 2009 2010 2009 2010 
 2007 2009 2009 2010 2009 2010 


 (in thousands, except per unit data)
 
 (in thousands, except per unit data)
 

Statement of Operations Data:

Statement of Operations Data:

 

Statement of Operations Data:

 

Total revenues

Total revenues

 $403,452 $438,924 $419,790 $116,706 $66,603 $419,790 $66,603 

Total revenues

 $403,452 $438,924 $419,790 $226,095 $145,031 $419,790 $145,031 

Costs and expenses:

Costs and expenses:

 

Costs and expenses:

 

Cost of operations (exclusive of depreciation, depletion and amortization shown separately below)

 318,405 364,912 336,335 98,317 46,352 336,335 46,352 

Cost of operations (exclusive of depreciation, depletion and amortization shown separately below)

 318,405 364,912 336,335 183,518 104,192 336,335 104,192 

Freight and handling costs

 4,021 10,223 3,990 938 673 3,990 673 

Freight and handling costs

 4,021 10,223 3,990 1,976 1,444 3,990 1,444 

Depreciation, depletion and amortization

 30,750 36,428 36,279 9,974 7,765 36,279 7,765 

Depreciation, depletion and amortization

 30,750 36,428 36,279 19,872 15,803 36,279 15,803 

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

 15,370 19,042 16,754 4,376 3,678 16,754 3,678 

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

 15,370 19,042 16,754 8,989 7,604 16,754 7,604 

(Gain) loss on sale of assets

 (944) 451 1,710  (1) 1,710 (1)

(Gain) loss on sale of assets

 (944) 451 1,710 1,288 (47) 1,710 (47)
                               

Income from operations

Income from operations

 35,849 7,868 24,721 3,101 8,136 24,721 8,136 

Income from operations

 35,849 7,868 24,721 10,452 16,035 24,721 16,035 

Interest and other income (expense):

Interest and other income (expense):

 

Interest and other income (expense):

 

Interest expense

 (5,579) (5,501) (6,222) (1,170) (1,471) (4,291) (992)

Interest expense

 (5,579) (5,501) (6,222) (2,891) (2,781) (4,271) (1,875)

Interest income

 317 149 71 87 8 71 8 

Interest income

 317 149 71 69 18 71 18 

Equity in net income (loss) of unconsolidated affiliate(1)

  (1,587) 893 (43) (130) 893 (130)

Equity in net income (loss) of unconsolidated affiliate(1)

  (1,587) 893 (268) 414 893 414 
                               

Total interest and other income (expense)

Total interest and other income (expense)

 (5,263) (6,939) (5,259) (1,125) (1,592) (3,327) (1,114)

Total interest and other income (expense)

 (5,263) (6,939) (5,259) (3,089) (2,349) (3,307) (1,443)

Income tax benefit

Income tax benefit

 (126)       

Income tax benefit

 (126)       
                               

Net income

Net income

 $30,714 $929 $19,462 $1,976 $6,544 $21,394 $7,023 

Net income

 $30,714 $929 $19,462 $7,362 $13,686 $21,413 $14,592 
                               

Net income per limited partner unit, basic:

Net income per limited partner unit, basic:

 

Net income per limited partner unit, basic:

 

Common units

           $1.306 $0.360 

Common units

           $1.306 $0.581 

Subordinated units

           $0.385 $0.196 

Subordinated units

           $0.387 $0.573 

Net income per limited partner unit, diluted:

Net income per limited partner unit, diluted:

 

Net income per limited partner unit, diluted:

 

Common units

           $1.304 $0.358 

Common units

           $1.305 $0.578 

Subordinated units

           $0.385 $0.196 

Subordinated units

           $0.387 $0.573 

Weighted average number of limited partner units outstanding, basic:

Weighted average number of limited partner units outstanding, basic:

 

Weighted average number of limited partner units outstanding, basic:

 

Common units

           12,397,000 12,397,000 

Common units

           12,397,000 12,397,000 

Subordinated units

           12,397,000 12,397,000 

Subordinated units

           12,397,000 12,397,000 

Weighted average number of limited partner units outstanding, diluted:

Weighted average number of limited partner units outstanding, diluted:

 

Weighted average number of limited partner units outstanding, diluted:

 

Common units

           12,411,479 12,447,417 

Common units

           12,410,073 12,445,073 

Subordinated units

           12,397,000 12,397,000 

Subordinated units

           12,397,000 12,397,000 

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 Rhino Energy LLC Historical  
  
 
 Rhino Energy LLC Historical  
  
 


 Consolidated Condensed
Consolidated
 Rhino Resource Partners LP
Pro Forma Condensed
Consolidated
 
 Consolidated Condensed
Consolidated
 Rhino Resource Partners LP
Pro Forma Condensed
Consolidated
 


 Year Ended December 31, Three Months Ended
March 31,
 Year Ended
December 31,
 Three Months
Ended
March 31,
 
 Year Ended December 31, Six Months Ended
June 30,
 Year Ended
December 31,
 Six Months
Ended
June 30,
 


  
 2008
(as restated)
  
 
  
 2008
(as restated)
  
 


 2007 2009 2009 2010 2009 2010 
 2007 2009 2009 2010 2009 2010 


 (in thousands, except per ton data)
 
 (in thousands, except per ton data)
 

Statement of Cash Flows Data:

Statement of Cash Flows Data:

 

Statement of Cash Flows Data:

 

Net cash provided by (used in):

Net cash provided by (used in):

 

Net cash provided by (used in):

 

Operating activities

 $52,493 $57,211 $41,495 $3,274 $4,555     

Operating activities

 $52,493 $57,211 $41,495 $20,222 $24,871     

Investing activities

 $(28,098)$(106,638)$(27,345)$(11,732)$(6,541)     

Investing activities

 $(28,098)$(106,638)$(27,345)$(19,424)$(11,588)     

Financing activities

 $(21,192)$47,781 $(15,401)$7,028 $1,647     

Financing activities

 $(21,192)$47,781 $(15,401)$(2,292)$(13,781)     

Other Financial Data:

Other Financial Data:

 

Other Financial Data:

 

EBITDA

EBITDA

 $66,917 $42,858 $61,964 $13,119 $15,779 $61,964 $15,779 

EBITDA

 $66,917 $42,858 $61,964 $30,125 $32,270 $61,964 $32,270 

Capital expenditures (1)

Capital expenditures (1)

 $32,773 $92,741 $29,657 $10,965 $6,637 $29,657 $6,637 

Capital expenditures (1)

 $32,773 $92,741 $29,657 $18,825 $11,498 $29,657 $11,498 

Balance Sheet Data (at period end):

Balance Sheet Data (at period end):

 

Balance Sheet Data (at period end):

 

Cash and cash equivalents

Cash and cash equivalents

 $3,583 $1,937 $687 $508 $347 $687 $347 

Cash and cash equivalents

 $3,583 $1,937 $687 $443 $188   $188 

Property and equipment, net

Property and equipment, net

 $211,657 $282,863 $270,680 $283,685 $269,603 $270,680 $269,603 

Property and equipment, net

 $211,657 $282,863 $270,680 $278,124 $266,357   $266,357 

Total assets

Total assets

 $275,992 $352,536 $339,985 $369,112 $347,488 $339,985 $347,488 

Total assets

 $275,992 $352,536 $339,985 $350,652 $340,897   $340,897 

Total liabilities

Total liabilities

 $158,152 $234,225 $201,584 $248,825 $202,543 $134,634 $135,593 

Total liabilities

 $158,152 $234,225 $201,584 $225,027 $188,811   $121,178 

Total debt

Total debt

 $83,954 $138,027 $122,137 $145,107 $123,833 $55,187 $56,883 

Total debt

 $83,954 $138,027 $122,137 $137,146 $108,454   $40,821 

Members'/partners' equity

Members'/partners' equity

 $117,841 $118,311 $138,401 $120,287 $144,944 $205,351 $211,894 

Members'/partners' equity

 $117,841 $118,311 $138,401 $125,625 $152,086   $219,719 

Operating Data (2):

Operating Data (2):

 

Operating Data (2):

 

Tons of coal sold

Tons of coal sold

 8,159 7,977 6,699 1,939 949 6,699 949 

Tons of coal sold

 8,159 7,977 6,699 3,696 2,042 6,699 2,042 

Tons of coal produced/purchased

Tons of coal produced/purchased

 8,024 8,017 6,732 1,991 1,044 6,732 1,044 

Tons of coal produced/purchased

 8,024 8,017 6,732 3,742 2,176 6,732 2,176 

Coal revenues per ton (3)

Coal revenues per ton (3)

 $48.30 $51.25 $59.98 $58.33 $65.98 $59.98 $65.98 

Coal revenues per ton (3)

 $48.30 $51.25 $59.98 $59.06 $66.96 $59.98 $66.96 

Cost of operations per ton (4)

Cost of operations per ton (4)

 $39.02 $45.75 $50.21 $50.69 $48.82 $50.21 $48.82 

Cost of operations per ton (4)

 $39.02 $45.75 $50.21 $49.66 $51.02 $50.21 $51.02 

(1)
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 
 Rhino Energy LLC Historical 


 Consolidated Condensed
Consolidated
 
 Consolidated Condensed
Consolidated
 


 Year Ended December 31, Three Months Ended
March 31,
 
 Year Ended December 31, Six Months Ended
June 30,
 


 2007 2008 2009 2009 2010 
 2007 2008 2009 2009 2010 


 (in thousands)
 
 (in thousands)
 

Reconciliation of total capital expenditures to net cash used for capital expenditures:

Reconciliation of total capital expenditures to net cash used for capital expenditures:

 

Reconciliation of total capital expenditures to net cash used for capital expenditures:

 

Additions to property, plant and equipment

Additions to property, plant and equipment

 $14,599 $78,076 $27,836 $9,144 $6,637 

Additions to property, plant and equipment

 $14,599 $78,076 $27,836 $17,004 $11,440 

Acquisitions of coal companies and coal properties

Acquisitions of coal companies and coal properties

 18,174 14,665 1,821 1,821  

Acquisitions of coal companies and coal properties

 18,174 14,665   58 

Acquisition of roof bolt manufacturing company

Acquisition of roof bolt manufacturing company

   1,821 1,821  
                       

Net cash used for capital expenditures

Net cash used for capital expenditures

 32,773 92,741 29,657 10,965 6,637 

Net cash used for capital expenditures

 32,773 92,741 29,657 18,825 11,498 
                       

Plus:

Plus:

 

Plus:

 

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

      

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

      
                       

Total capital expenditures

Total capital expenditures

 $32,773 $92,741 $29,657 $10,965 $6,637 

Total capital expenditures

 $32,773 $92,741 $29,657 $18,825 $11,498 
                       
(2)
In May 2008, we entered into a joint venture with an affiliate of Patriot Coal Corporation, or Patriot, that acquired the Rhino Eastern mining complex which commenced production in August 2008. We have a 51% membership interest in, and serve as manager for, the joint venture. The operating data do not include data with respect to the Rhino Eastern mining complex. The joint venture produced and sold approximately 0.2 million tons and approximately 0.1 million tons of premium mid-vol metallurgical coal for the year ended December 31, 2009 and the threesix months ended March 31,June 30, 2010, respectively.
(3)
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.
(4)
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.

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Non-GAAP Financial Measure

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

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

        EBITDA as presented below may not be comparable to similarly titled measures of other companies. The following table presents a reconciliation of EBITDA to the most directly comparable GAAP financial measures, on a historical basis and pro forma basis, as applicable, for each of the periods indicated.indicated:



 Rhino Energy LLC Historical  
  
 
 Rhino Energy LLC Historical  
  
 


 Consolidated Condensed
Consolidated
 Rhino Resource Partners LP
Pro Forma Condensed
Consolidated
 
 Consolidated Condensed
Consolidated
 Rhino Resource Partners LP
Pro Forma Condensed
Consolidated
 


 Year Ended December 31, Three Months
Ended
March 31,
 Year Ended December 31, Three Months
Ended
March 31,
 
 Year Ended December 31, Six Months
Ended
June 30,
 Year Ended December 31, Six Months
Ended
June 30,
 


  
 2008
(as restated)
  
 
  
 2008
(as restated)
  
 


 2007 2009 2009 2010 2009 2010 
 2007 2009 2009 2010 2009 2010 


 (in thousands)
 
 (in thousands)
 

Reconciliation of EBITDA to net income:

Reconciliation of EBITDA to net income:

 

Reconciliation of EBITDA to net income:

 

Net income

Net income

 $30,714 $929 $19,462 $1,976 $6,544 $21,394 $7,023 

Net income

 $30,714 $929 $19,462 $7,362 $13,686 $21,413 $14,592 

Plus:

Plus:

 

Plus:

 

Depreciation, depletion and amortization

 30,750 36,428 36,279 9,974 7,765 36,279 7,765 

Depreciation, depletion and amortization

 30,750 36,428 36,279 19,872 15,803 36,279 15,803 

Interest expense

 5,579 5,501 6,222 1,170 1,471 4,291 992 

Interest expense

 5,579 5,501 6,222 2,891 2,781 4,271 1,875 

Less:

Less:

 

Less:

 

Income tax benefit

 126       

Income tax benefit

 126       
                               

EBITDA

EBITDA

 $66,917 $42,858 $61,964 $13,119 $15,779 $61,964 $15,779 

EBITDA

 $66,917 $42,858 $61,964 $30,125 $32,270 $61,964 $32,270 
                               

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 Rhino Energy LLC Historical 
 Rhino Energy LLC Historical 


 Consolidated Condensed
Consolidated
 
 Consolidated Condensed
Consolidated
 


 Year Ended December 31, Three Months
Ended
March 31,
 
 Year Ended December 31, Six Months
Ended
June 30,
 


  
 2008
(as restated)
  
 
  
 2008
(as restated)
  
 


 2007 2009 2009 2010 
 2007 2009 2009 2010 


 (in thousands)
 
 (in thousands)
 

Reconciliation of EBITDA to net cash provided by operating activities:

Reconciliation of EBITDA to net cash provided by operating activities:

 

Reconciliation of EBITDA to net cash provided by operating activities:

 

Net cash provided by operating activities

Net cash provided by operating activities

 $52,493 $57,211 $41,495 $3,274 $4,555 

Net cash provided by operating activities

 $52,493 $57,211 $41,495 $20,222 $24,871 

Plus:

Plus:

 

Plus:

 

Increase in net operating assets

 10,553  17,190 9,601 10,828 

Increase in net operating assets

 10,553  17,190 10,290 5,827 

Decrease in provision for doubtful accounts

 175     

Decrease in provision for doubtful accounts

 175     

Gain on sale of assets

 944    1 

Gain on sale of assets

 944     47 

Gain on retirement of advance royalties

 115     

Gain on retirement of advance royalties

 115   77  

Interest expense

 5,579 5,501 6,222 1,170 1,471 

Interest expense

 5,579 5,501 6,222 2,891 2,781 

Settlement of litigation

   1,773   

Settlement of litigation

   1,773   

Equity in net income of unconsolidated affiliate

   893   

Equity in net income of unconsolidated affiliate

   893  414 

Less:

Less:

 

Less:

 

Decrease in net operating assets

  10,440    

Decrease in net operating assets

  10,440    

Accretion on interest-free debt

 360 569 200 44 49 

Accretion on interest-free debt

 360 569 200 193 98 

Amortization of advance royalties

 700 471 215 83 276 

Amortization of advance royalties

 700 471 215 156 374 

Increase in provision for doubtful accounts

   19   

Increase in provision for doubtful accounts

   19   

Loss on sale of assets

  451 1,710   

Loss on sale of assets

  451 1,710 1,288  

Loss on retirement of advance royalties

  45 712  78 

Loss on retirement of advance royalties

  45 712  113 

Income tax benefit

 126     

Income tax benefit

 126     

Accretion on asset retirement obligations

 1,757 2,709 2,753 756 542 

Accretion on asset retirement obligations

 1,757 2,709 2,753 1,450 1,085 

Equity in net loss of unconsolidated affiliate

  1,587  43 130 

Equity in net loss of unconsolidated affiliate

  1,587  268  

Payment of abandoned public offering expenses (a)

  3,582    

Payment of abandoned public offering expenses (a)

  3,582    
                       

EBITDA

EBITDA

 $66,917 $42,858 $61,964 $13,119 $15,779 

EBITDA

 $66,917 $42,858 $61,964 $30,125 $32,270 
                       

(a)
In 2008, we attempted an initial public offering, which was not consummated. We recorded the related deferred costs as a selling, general and administrative, or SG&A, expense in August of that year.

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RISK FACTORS

        Limited partner interests are inherently different from the capital stock of a corporation, although many of the business risks to which we are subject are similar to those that would be faced by a corporation engaged in a similar business. You should carefully consider the following risk factors together with all of the other information included in this prospectus in evaluating an investment in our common units.

        If any of the following risks were to occur, our business, financial condition, results of operations and cash available for distribution could be materially adversely affected. In that case, we might not be able to make distributions on our common units, the trading price of our common units could decline, and you could lose all or part of your investment.

Risks Inherent in Our Business

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

        We may not have sufficient cash each quarter to pay the full amount of our minimum quarterly distribution of $0.445 per unit, or $1.78 per unit per year, which will require us to have available cash of approximately $11.3 million per quarter, or $45.0 million per year, based on the number of common and subordinated units and the general partner interest to be outstanding after the completion of this offering. The amount of cash we can distribute on our common and subordinated units principally depends upon the amount of cash we generate from our operations, which will fluctuate from quarter to quarter based on, among other things:


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        For a description of additional restrictions and factors that may affect our ability to pay cash distributions, please read "Cash Distribution Policy and Restrictions on Distributions."

We must generate approximately $45.0 million of available cash from operating surplus to pay the minimum quarterly distribution for four quarters on all of our common units and subordinated units that will be outstanding immediately after this offering and the corresponding distribution on our general partner interest. For the year ended December 31, 2009 and the twelve months ended March 31,June 30, 2010, we would have generated approximately $33.4$11.6 million and $39.3$1.5 million, respectively, less than the amount of available cash from operating surplus respectively, and would have been ableneeded to pay the full minimum quarterly distribution on all of our common units, but only approximately 48.3% and 74.8%, respectively, of the minimum quarterly distribution on ouras a whole, including subordinated units, during those periods.

        We must generate approximately $45.0 million (or approximately $11.3 million per quarter) of available cash to pay the minimum quarterly distribution for four quarters on all of our common units and subordinated units that will be outstanding immediately after this offering and the corresponding distribution on our general partner interest. We did not generate $45.0 million of available cash from operating surplus during the year ended December 31, 2009 or the twelve months ended March 31,June 30, 2010. The amount of available cash from operating surplus we generated with respect to those periods was approximately $33.4 million and $39.3$43.6 million, respectively. Asrespectively, or approximately $11.6 million and $1.5 million, respectively, less than the amount needed to pay the full minimum quarterly distribution on all units as a result, forwhole, including subordinated units. For those periods, we would have generated aggregate available cash sufficient to pay 100% of the aggregate minimum quarterly distribution on our common units, but only approximately 48.3%48.4% and 74.8%93.5%, respectively, of the minimum quarterly distribution on our subordinated units during those periods. We have not usedcalculated available cash on a quarter-by-quarter estimatesbasis for each quarter in the year ended December 31, 2009 andor the twelve months ended March 31,June 30, 2010 to determine if we would have generated available cash sufficient to pay the minimum quarterly distribution for each quarter during those periods.

The assumptions underlying our forecast of cash available for distribution included in "Cash Distribution Policy and Restrictions on Distributions" are inherently uncertain and subject to significant business, economic, financial, regulatory and competitive risks and uncertainties that could cause cash available for distribution to differ materially from those estimated.

        We would have generated sufficient cash available for distribution to pay 100% of the minimum quarterly distribution on all of our common units during the year ended December 31, 2009 and the twelve months ended March 31,June 30, 2010, but only approximately 48.3%48.4% and 74.8%93.5%, respectively, of the minimum quarterly distribution on our subordinated units during those periods. The forecast of cash available for distribution set forth in "Cash Distribution Policy and Restrictions on Distributions" includes our forecast of our results of operations and cash available for distribution for the twelve months ending JuneSeptember 30, 2011. Our ability to pay the full minimum quarterly distribution in the forecast period is based on a number of assumptions that


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may not prove to be correct, which are discussed in "Cash Distribution Policy and Restrictions on Distributions." These assumptions include, but are not limited to, the following:


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        Our forecast of cash available for distribution has been prepared by management, and we have not received an opinion or report on it from any independent registered public accountants. The assumptions underlying our forecast of cash available for distribution are inherently uncertain and are subject to significant business, economic, financial, regulatory and competitive risks and uncertainties that could cause cash available for distribution to differ materially from that which is forecasted. If we do not achieve our forecasted results, we may not be able to pay the minimum quarterly distribution or any amount on our common units or subordinated units, in which event the market price of our common units may decline materially. Please read "Cash Distribution Policy and Restrictions on Distributions."

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

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


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        Any adverse change in these factors could result in weaker demand and lower prices for our products. In addition, the recent global economic downturn, particularly with respect to the U.S. economy, coupled with the global financial and credit market disruptions, have had an impact on the coal industry generally and may continue to do so until economic conditions improve. The demand for electricity in the United States decreased during 2009 as compared to 2008, which led to a decline in the demand for and prices of coal. The demand for electricity may remain at low levels or further decline if economic conditions remain weak. If these trends continue, we may not be able to sell all of the coal we are capable of producing or sell our coal at prices comparable to recent years. Recent low prices for natural gas, which is a substitute for coal generated power, may also lead to continued decreased coal consumption by electricity-generating utilities. A substantial or extended decline in the prices we receive for our coal supply contracts could materially and adversely affect our results of operations.


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

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

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

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

        The coal mining industry is subject to numerous and extensive federal, state and local environmental laws and regulations, including laws and regulations pertaining to permitting and


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


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increased substantially. As a result, the consequences for any noncompliance may become more significant in the future.

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

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

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

        In 2006, the Federal Mine Improvement and New Emergency Response Act of 2006, or the MINER Act, was enacted. The MINER Act significantly amended the Federal Mine Safety and Health Act of 1977, or the Mine Act, imposing more extensive and stringent compliance standards, increasing criminal penalties and establishing a maximum civil penalty for non-compliance, and expanding the scope of federal oversight, inspection, and enforcement activities. Following the passage of the MINER Act, the U.S. Mine Safety and Health Administration, or MSHA, issued new or more stringent rules and policies on a variety of topics, including:


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        Subsequent to passage of the MINER Act, Illinois, Kentucky, Pennsylvania, Ohio and West Virginia have enacted legislation addressing issues such as mine safety and accident reporting, increased civil and criminal penalties, and increased inspections and oversight. Other states may pass similar legislation in the future. Also, additional federal and state legislation that further increase mine safety regulation, inspection and enforcement, particularly with respect to


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underground mining operations, has been considered in light of recent fatal mine accidents. Further workplace accidents are likely to also result in more stringent enforcement and possibly the passage of new laws and regulations.

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

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

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

        Recently, our Mine 28 was included on a list of forty eight48 mines that would have faced "pattern of violation" sanctions had the owners/operators of such mines not contested the notices of violation. This list was publicly released by U.S. Representative George Miller on April 14, 2010. MSHA inspected Mine 28 again promptly thereafter, and issued additional notices of violation. As a result of these and future inspections and alleged violations, we could be subject to material fines, penalties or sanctions. Mine 28, as well as any of our other mines, could be subject to a temporary or extended shut down as a result of an alleged MSHA violation. Any such penalties, fines or sanctions could have a material adverse effect on our business, results of operations and cash available for distribution.

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

        Numerous governmental permits and approvals are required for mining operations, and we can face delays, challenges to, and difficulties in acquiring, maintaining or renewing necessary permits and approvals, including environmental permits. The permitting rules, and the interpretations of these rules, are complex, change frequently, and are often subject to discretionary interpretations by regulators, all of which may make compliance more difficult or


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impractical, and may possibly preclude the continuance of ongoing mining operations or the development of future mining operations. In addition, the public has certain statutory rights to comment upon and otherwise impact the permitting process, including through court intervention. Over the past few years, the length of time needed to bring a new surface mine into production has increased because of the increased time required to obtain necessary permits. The slowing pace at which permits are issued or renewed for new and existing mines has materially impacted production in certain regions, primarily in Central Appalachia, but could also affect Northern Appalachia and other regions in the future.

        Individual or general permits under Section 404 of the federal Clean Water Act, or the 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, or the Corps, is authorized to issue "nationwide" permits for specific categories of activities that are similar in nature and that are determined to have minimal adverse environmental effects. Nationwide Permit 21, or NWP 21, authorizes the disposal of dredged or fill material from mining activities into the waters of the United States. However on June 17, 2010, the Corps suspended the use of


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NWP 21, but NWP 21 authorizations already granted remain in effect. Individual Section 404 permits for valley fill surface mining activities, which we also currently utilize, are subject to legal uncertainties. On March 23, 2007, the United States District Court for the Southern District of West Virginia rescinded several individual Section 404 permits issued to other mining operations based on a finding that the Corps issued the permits in violation of the CWA and the National Environmental Policy Act, or NEPA. This decision is currently on appeal to the United States Court of Appeals for the Fourth Circuit. Additionally, on March 26, 2010, the U.S. Environmental Protection Agency, or EPA, announced a proposal to exercise its Section 404(c) "veto" power with regard to the Spruce No. 1 Surface Mine in West Virginia, which was previously permitted in 2007. This would be the first time the EPA's Section 404(c) "veto" power would be applied to a previously permitted project. Moreover, on April 1, 2010, the EPA issued interim final guidance substantially revising the environmental review of Section 402 and Section 404 permits by state and federal agencies. Please read "Business—Regulation and Laws—Clean Water Act" for a discussion of recent litigation and regulatory developments related to the CWA. An inability to conduct our mining operations pursuant to applicable permits would reduce our production and cash flows, which could limit our ability to make distributions to our unitholders.

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

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

        These risks include:


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


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

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

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

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


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

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


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

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

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

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

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

        Our results of operations and cash available for distribution to our unitholders depend substantially on obtaining coal reserves that have geological characteristics that enable them to be mined at competitive costs and to meet the coal quality needed by our customers. Because we deplete our reserves as we mine coal, our future success and growth will depend, in part, upon our ability to acquire additional coal reserves that are economically recoverable. If we fail to


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acquire or develop additional reserves, our existing reserves will eventually be depleted. Replacement reserves may not be available when required or, if available, may not be capable of being mined at costs comparable to those characteristic of the depleting mines. We may not be able to accurately assess the geological characteristics of any reserves that we acquire, which may adversely affect our results of operations and cash available for distribution to our unitholders. Exhaustion of reserves at particular mines with certain valuable coal characteristics also may have an adverse effect on our operating results that is disproportionate to the percentage of overall production represented by such mines. Our ability to obtain other reserves in the future could be limited by restrictions under our existing or future debt agreements, competition from other coal companies for attractive properties, the lack of suitable acquisition candidates or the inability to acquire coal properties on commercially reasonable terms.


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

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

        For these reasons, estimates of the quantities and qualities of the economically recoverable coal attributable to any particular group of properties, classifications of coal reserves and non-reserve coal deposits based on risk of recovery, estimated cost of production and estimates of net cash flows expected from particular reserves as prepared by different engineers or by the


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same engineers at different times may vary materially due to changes in the above factors and assumptions. Actual production from identified coal reserve and non-reserve coal deposit areas or properties and revenues and expenditures associated with our and the joint venture's mining operations may vary materially from estimates. Accordingly, these estimates may not reflect our and the joint venture's actual coal reserves or non-reserve coal deposits. Any inaccuracy in our estimates related to our and the joint venture's coal reserves and non-reserve coal deposits could result in lower than expected revenues and higher than expected costs, which could have a material adverse effect on our ability to make cash distributions.


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

        Our partnership agreement requires our general partner to deduct from operating surplus each quarter estimated maintenance capital expenditures as opposed to actual maintenance capital expenditures in order to reduce disparities in operating surplus caused by fluctuating maintenance capital expenditures, such as reserve replacement costs or refurbishment or replacement of mine equipment. Our initial annual estimated maintenance capital expenditures for purposes of calculating operating surplus will be approximately $15.5$18.6 million. This amount is based on our current estimates of the amounts of expenditures we will be required to make in the future to maintain our long-term operating capacity, which we believe to be reasonable. Our partnership agreement does not cap the amount of maintenance capital expenditures that our general partner may estimate. This amount has been taken into consideration in calculating our forecasted cash available for distribution in "Cash Distribution Policy and Restrictions on Distributions." The initial amount of our estimated maintenance capital expenditures may be more than our initial actual maintenance capital expenditures, which will reduce the amount of available cash from operating surplus that we would otherwise have available for distribution to unitholders. The amount of estimated maintenance capital expenditures deducted from operating surplus is subject to review and change by the board of directors of our general partner at least once a year, with any change approved by the conflicts committee. In addition to estimated maintenance capital expenditures, reimbursement of expenses incurred by our general partner and its affiliates will reduce the amount of available cash from operating surplus that we would otherwise have available for distribution to our unitholders. Please see "Risks Inherent in an Investment in Us—Cost reimbursements due to our general partner and its affiliates for services provided to us or on our behalf will reduce cash available for distribution to our unitholders. The amount and timing of such reimbursements will be determined by our general partner."

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

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


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

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


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        In the wake of the Supreme Court's April 2, 2007 decision inMassachusetts, et al. v. EPA, which held that greenhouse gases fall under the definition of "air pollutant" in the federal Clean Air Act, or CAA, in December 2009, the Environmental Protection Agency, or EPA, issued a final rule declaring that six greenhouse gases, including carbon dioxide and methane, "endanger both the public health and the public welfare of current and future generations." The issuance of this "endangerment finding" allows the EPA to begin regulating greenhouse gas emissions under existing provisions of the federal CAA. In late September and early October 2009, in anticipation of the issuance of the endangerment finding, the EPA officially proposed two sets of rules regarding possible future regulation of greenhouse gas emissions under the CAA. One of these proposals would require the use of the best available control technology for greenhouse gas emissions whenever certain stationary sources, such as power plants, are built or significantly modified.

        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 and cash available for distribution to our unitholders. Please read "Business—Regulation and Laws—Carbon Dioxide Emissions."

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

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


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terms less favorable to us upon those renewals. The failure to maintain or the inability to acquire sufficient surety bonds, as required by state and federal laws, could subject us to fines and penalties as well as the loss of our mining permits. Such failure could result from a variety of factors, including:


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        We maintain surety bonds with third parties for reclamation expenses and other miscellaneous obligations. It is possible that we may in the future have difficulty maintaining our surety bonds for mine reclamation. Due to current economic conditions and the volatility of the financial markets, surety bond providers may be less willing to provide us with surety bonds or maintain existing surety bonds or may demand terms that are less favorable to us than the terms we currently receive. We may have greater difficulty satisfying the liquidity requirements under our existing surety bond contracts. As of March 31,June 30, 2010, we had $65.8$65.9 million in reclamation surety bonds, secured by $18.5$18.2 million in letters of credit outstanding under our credit agreement. Our credit agreement provides for a $200 million working capital revolving credit agreement, 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 agreement 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 Agreement." If we do not maintain sufficient borrowing capacity or have other resources to satisfy our surety and bonding requirements, our operations and cash available for distribution to our unitholders could be adversely affected.

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

        We sell a material portion of our coal under supply contracts. As of July 13,August 23, 2010 we had sales commitments for approximately 99%97% and 80%69% of our estimated coal production (including purchased coal to supplement our production and excluding results from the joint venture) for the year ending December 31, 2010 and the twelve months ending JuneSeptember 30, 2011, respectively. When our current contracts with customers expire, our customers may decide not to extend or enter into new contracts. As of July 13,August 23, 2010, we had supply contracts for commitments that expire between JulyDecember 31, 2010 and December 31, 2014.2013. Of these committed tons, under the terms of the supply contracts, we will ship 20%22% during the remainder of 2010, 36% in 2011, 26% in 2011, 24%2012 and 16% in 2012, 21% in 2013 and 9% in 2014.2013. We derived approximately 85%85.0% and 86%81.1% of our total revenues from coal sales (excluding results from the joint venture) to our ten largest customers for the year ended December 31, 2009 and the threesix months ended March 31,June 30, 2010, respectively, with affiliates of our top three customers accounting for approximately 52.2% and approximately 48.6%44.1% of our coal sales revenues for the year ended December 31, 2009 and the threesix months ended March 31,June 30, 2010, respectively.

        In the absence of long-term contracts, our customers may decide to purchase fewer tons of coal than in the past or on different terms, including different pricing terms. Negotiations to


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extend existing contracts or enter into new long-term contracts with those and other customers may not be successful, and those customers may not continue to purchase coal from us under long-term coal supply contracts or may significantly reduce their purchases of coal from us. Due to the recent volatility in the market prices for metallurgical coal, there has been a recent trend towards quarterly supply contracts. As a result, customers may be less willing to enter into long-term coal supply contracts for our metallurgical coal. In addition, interruption in the purchases by or operations of our principal customers could significantly affect our results of operations and cash available for distribution. Unscheduled maintenance outages at our customers' power plants and unseasonably moderate weather are examples of conditions that might cause our customers to reduce their purchases. Our mines may have difficulty identifying alternative purchasers of their coal if their existing customers suspend or terminate their purchases. The amount and terms of sales of coal produced from our Rhino Eastern mining complex are controlled by an affiliate of Patriot pursuant to the joint venture agreement. We


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cannot guarantee that Patriot will be successful in obtaining coal supply contracts at favorable prices, if at all, which could have a material adverse effect on our results of operations and cash available for distribution to our unitholders. For additional information relating to these contracts, please read "Business—Customers—Coal Supply Contracts."

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

        Excluding results from the joint venture, steam coal accounted for approximately 95% of our coal sales volume for the year ended December 31, 2009 and approximately 86%85% of our coal sales volume for the threesix months ended March 31,June 30, 2010. The majority of our sales of steam coal for the year ended December 31, 2009 and the threesix months ended March 31,June 30, 2010 were to electric utilities for use primarily as fuel for domestic electricity consumption. According to the U.S. Department of Energy's Energy Information Administration, the domestic electric utility industry accounted for approximately 94% of domestic coal consumption in 2009. The amount of coal consumed by the domestic electric utility industry is affected primarily by the overall demand for electricity, environmental and other governmental regulations, and the price and availability of competing fuels for power plants such as nuclear, natural gas and oil as well as alternative sources of energy. We compete generally with producers of other fuels, such as natural gas and oil. A decline in price for these fuels, could cause demand for coal to decrease and adversely affect the price of our coal. For example, low natural gas prices have led, in some instances, to decreased coal consumption by electricity-generating utilities. If alternative energy sources, such as nuclear, hydroelectric, wind or solar, become more cost-competitive on an overall basis, demand for coal could decrease and the price of coal could be materially and adversely affected. Further, legislation requiring, subsidizing or providing tax benefit for the use of alternative energy sources and fuels, or legislation providing financing or incentives to encourage continuing technological advances in this area, could further enable alternative energy sources to become more competitive with coal. A decrease in coal consumption by the domestic electric utility industry could adversely affect the price of coal, which could materially adversely affect our results of operations and cash available for distribution to our unitholders.

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

        Price adjustment, "price re-opener" and other similar provisions in our supply contracts may reduce the protection from short-term coal price volatility traditionally provided by such contracts. As of July 22, 2010, one of our coal supply contracts relating to sales commitments for


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our estimated coal production through 2014 containedPrice re-opener provisions that allow for the purchase price to be renegotiated at periodic intervals. This price re-opener provision requirestypically require the parties to agree on a new price. Failure of the parties to agree on a price under thea price re-opener provision can lead to termination of the contract. Any adjustment or renegotiations leading to a significantly lower contract price could adversely affect our results of operations and cash available for distribution to our unitholders. We are currently renegotiating the purchase price pursuant to this price re-opener provision. If we fail to agree on a new price prior to October 1, 2010, this coal supply contract will terminate.

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


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

        We at times use contractors to operate certain of our mines. For both the year ended December 31, 2009 and the threesix months ended March 31,June 30, 2010, approximately 4% of our total coal production was from contractor-operated mines. Disruption in our supply of coal produced by these contractors 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 our contractors. Any increase in the prices we pay for contractor-produced coal could increase our costs and therefore adversely affect our results of operations and cash available for distribution to our unitholders.

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

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


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

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

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

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

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

        The Federal Surface Mining Control and Reclamation Act of 1977 and counterpart state laws and regulations establish operational, reclamation and closure standards for all aspects of surface mining as well as most aspects of underground mining. Estimates of our total reclamation and


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mine closing liabilities are based upon permit requirements and our engineering expertise related to these requirements. The estimate of ultimate reclamation liability is reviewed both periodically by our management and annually by independent third-party engineers. The estimated liability can change significantly if actual costs vary from assumptions or if governmental regulations change significantly. Please read "Management's Discussion and Analysis of Financial Condition and Results of Operations—Critical Accounting Policies and Estimates—Asset Retirement Obligations." Wexford will not indemnify us against any reclamation or mine closing liabilities associated with our assets.

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

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

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

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


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        Increases in our total indebtedness would increase our total interest expense, which would in turn reduce our forecasted cash available for distribution. As of December 31, 2009 our current portion of long-term debt that will be funded from cash flows from operating activities during 2010 was approximately $2.2 million. Our ability to service our indebtedness will depend upon, among other things, our future financial and operating performance, which will be affected by prevailing economic conditions and financial, business, regulatory and other factors, some of which are beyond our control. If our operating results are not sufficient to service our current or future indebtedness, we will be forced to take actions such as reducing distributions, reducing or delaying our business activities, acquisitions, investments and/or capital expenditures, selling assets, restructuring or refinancing our indebtedness, or seeking additional equity capital or bankruptcy protection. We may not be able to effect any of these remedies on satisfactory terms, or at all.


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

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


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        In addition, our payment of principal and interest on our debt will reduce cash available for distribution on our units. Our credit agreement limits our ability to pay distributions upon the occurrence of the following events, among others, which would apply to us and our subsidiaries:

        Any subsequent refinancing of our current debt or any new debt could have similar restrictions. Our ability to comply with the covenants and restrictions contained in our credit agreement may be affected by events beyond our control, including prevailing economic, financial and industry conditions. If market or other economic conditions deteriorate, our ability to comply with these covenants may be impaired. If we violate any of the restrictions, covenants, ratios or tests in our credit agreement, a significant portion of our indebtedness may become immediately due and payable, and our lenders' commitment to make further loans to us may terminate. We might not have, or be able to obtain, sufficient funds to make these accelerated payments. In addition, our obligations under our credit agreement will be secured by substantially all of our assets, and if we are unable to repay our indebtedness under our credit agreement, the lenders could seek to foreclose on such assets.


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

Risks Inherent in an Investment in Us

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

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


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

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

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


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

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


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

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

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

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

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


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    whether to elect to reset target distribution levels; and

    whether or not to consent to any merger or consolidation of the partnership or amendment to the partnership agreement.

        By purchasing a common unit, a unitholder is treated as having consented to the provisions in the partnership agreement, including the provisions discussed above. Please read "Conflicts of Interest and Fiduciary Duties—Fiduciary Duties."


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Our partnership agreement restricts the remedies available to holders of our common and subordinated units for actions taken by our general partner that might otherwise constitute breaches of fiduciary duty.

        Our partnership agreement contains provisions that restrict the remedies available to unitholders for actions taken by our general partner that might otherwise constitute breaches of fiduciary duty under state fiduciary duty law. For example, our partnership agreement:

    provides that whenever our general partner makes a determination or takes, or declines to take, any other action in its capacity as our general partner, our general partner is required to make such determination, or take or decline to take such other action, in good faith, and will not be subject to any other or different standard imposed by our partnership agreement, Delaware law, or any other law, rule or regulation, or at equity;

    provides that our general partner will not have any liability to us or our unitholders for decisions made in its capacity as a general partner so long as it acted in good faith, meaning that it believed that the decision was in the best interest of our partnership;

    provides that our general partner and its officers and directors will not be liable for monetary damages to us or our limited partners resulting from any act or omission unless there has been a final and non-appealable judgment entered by a court of competent jurisdiction determining that our general partner or its officers and directors, as the case may be, acted in bad faith or engaged in fraud or willful misconduct or, in the case of a criminal matter, acted with knowledge that the conduct was criminal; and

    provides that our general partner will not be in breach of its obligations under the partnership agreement or its fiduciary duties to us or our limited partners if a transaction with an affiliate or the resolution of a conflict of interest is:

    (1)
    approved by the conflicts committee of the board of directors of our general partner, although our general partner is not obligated to seek such approval;

    (2)
    approved by the vote of a majority of the outstanding common units, excluding any common units owned by our general partner and its affiliates;

    (3)
    on terms no less favorable to us than those generally being provided to or available from unrelated third parties; or

    (4)
    fair and reasonable to us, taking into account the totality of the relationships among the parties involved, including other transactions that may be particularly favorable or advantageous to us.

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


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

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

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

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

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


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


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common units rather than retain the right to receive incentive distributions based on the initial target distribution levels. As a result, a reset election may cause our common unitholders to experience a reduction in the amount of cash distributions that our common unitholders would have otherwise received had we not issued new common units to our general partner in connection with resetting the target distribution levels. Please read "Provisions of Our Partnership Agreement Relating to Cash Distributions—General Partner's Right to Reset Incentive Distribution Levels."

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

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

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

        If our unitholders are dissatisfied with the performance of our general partner, they will have limited ability to remove our general partner. Unitholders initially will be unable to remove our general partner without its consent because our general partner and its affiliates will own sufficient units upon the completion of this offering to be able to prevent its removal. The vote of the holders of at least 662/3% of all outstanding common and subordinated units voting together as a single class is required to remove our general partner. Following the closing of this offering, Wexford will own an aggregate of 84.9%86.9% of our common and subordinated units (or 82.6%85.0% of our common and subordinated units, if the underwriters exercise their option to purchase additional common units in full). Also, if our general partner is removed without cause during the subordination period and no units held by the holders of the subordinated units or their affiliates are voted in favor of that removal, all remaining subordinated units will automatically be converted into common units and any existing arrearages on the common units will be extinguished. Cause is narrowly defined in our partnership agreement to mean that a


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court of competent jurisdiction has entered a final, non-appealable judgment finding our general partner liable for actual fraud or willful or wanton misconduct in its capacity as our general partner. Cause does not include most cases of charges of poor management of the business.

Unitholders will experience immediate and substantial dilution of $11.75$11.43 per common unit.

        The assumed initial public offering price of $20.00 per common unit exceeds pro forma net tangible book value of $8.25$8.57 per common unit. Based on the assumed initial public offering price of $20.00 per common unit, unitholders will incur immediate and substantial dilution of $11.75$11.43 per common unit. This dilution results primarily because the assets contributed to us by


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affiliates of our general partner are recorded at their historical cost in accordance with GAAP, and not their fair value. Please read "Dilution."

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

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

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

        If at any time our general partner and its affiliates own more than 90% of the common units, our general partner will have the right, but not the obligation, which it may assign to any of its affiliates or to us, to acquire all, but not less than all, of the common units held by unaffiliated persons at a price equal to the greater of (1) the average of the daily closing price of the common units over the 20 trading days preceding the date three days before notice of exercise of the call right is first mailed and (2) the highest per-unit price paid by our general partner or any of its affiliates for common units during the 90-day period preceding the date such notice is first mailed. If our general partner and its affiliates reduce their ownership percentage to below 70% of the outstanding common units, the ownership threshold to exercise the limited call rights will be reduced to 80%. As a result, unitholders may be required to sell their common units at an undesirable time or price and may not receive any return or a negative return on their investment. Unitholders may also incur a tax liability upon a sale of their units. Our general partner is not obligated to obtain a fairness opinion regarding the value of the common units to be repurchased by it upon exercise of the limited call right. There is no restriction in our partnership agreement that prevents our general partner from issuing additional common units and exercising its call right. If our general partner exercised its limited call right, the effect would be to take us private and, if the units were subsequently deregistered, we would no longer be subject to the reporting requirements of the Securities Exchange Act of 1934, or the Exchange Act. Upon consummation of this offering, and assuming no exercise of the underwriters' option to purchase additional common units, Wexford will own an aggregate of 84.9%86.9% of our common and subordinated units. At the end of the subordination period, assuming no additional issuances of units (other than upon the conversion of the subordinated units), Wexford will own 84.9%86.9% of our common units. For additional information about the limited call right, please read "The Partnership Agreement—Limited Call Right."


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

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


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

        After this offering, we will have 12,397,000 common units and 12,397,000 subordinated units outstanding, which includes the 3,750,0003,244,000 common units we are selling in this offering that may be resold in the public market immediately. All of the subordinated units will convert into common units on a one-for-one basis at the end of the subordination period. All of the 8,647,0009,153,000 common units (8,084,500(8,666,400 if the underwriters exercise in full their option to purchase additional common units)units in full) that are issued to Rhino Energy Holdings LLC will be subject to resale restrictions under a 180-day lock-up agreement with the underwriters. Each of the lock-up agreements with the underwriters may be waived in the discretion of certain of the underwriters. Sales by Wexford or other large holders of a substantial number of our common units in the public markets following this offering, or the perception that such sales might occur, could have a material adverse effect on the price of our common units or could impair our ability to obtain capital through an offering of equity securities. In addition, we have agreed to provide registration rights to Wexford. Under our agreement, our general partner and its affiliates have registration rights relating to the offer and sale of any units that they hold, subject to certain limitations. Please read "Units Eligible for Future Sale."

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

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


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

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


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

        While our partnership agreement requires us to distribute all of our available cash, our partnership agreement, including provisions requiring us to make cash distributions contained therein, may be amended. Our partnership agreement generally may not be amended during the subordination period without the approval of our public common unitholders. However, our partnership agreement can be amended with the consent of our general partner and the approval of a majority of the outstanding common units (including common units held by Wexford) after the subordination period has ended. At the closing of this offering, Wexford will own approximately 69.8%73.8% of the outstanding common units and all of our outstanding subordinated units. Please read "The Partnership Agreement—Amendment of the Partnership Agreement."

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

        Prior to this offering, there has been no public market for the common units. After this offering, there will be only 3,750,0003,244,000 publicly traded common units. 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. Unitholders may not be able to resell their common units 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 the common units and limit the number of investors who are able to buy the common units.

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


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    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 common units after this offering or changes in financial estimates by analysts;

    future sales of our common units; and

    the other factors described in these "Risk Factors."

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

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

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

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

            We have been approved to list our common units on the NYSE. Because we will be a publicly traded limited partnership, the NYSE does not require us to have a majority of independent directors on our general partner's board of directors or to establish a compensation committee or a nominating and corporate governance committee. Accordingly, unitholders will not have the same protections afforded to certain corporations that are subject to all of the NYSE corporate governance requirements. Please read "Management—Management of Rhino Resource Partners LP."


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

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

            Subsequent to the audit of our consolidated financial statements for the year ended December 31, 2009, our independent registered public accounting firm identified a deficiency in


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    our internal control over financial reporting as a result of a restatement of our consolidated financial statements as of December 31, 2008 which constituted a material weakness. A material weakness is a deficiency, or a combination of deficiencies, in internal control over financial reporting, such that there is a reasonable possibility that a material misstatement of the annual or interim financial statements will not be prevented or detected on a timely basis. As a result of the identified material weakness, we restated our consolidated historical financial statements for the year ended December 31, 2008. Please read Note 18 to the Rhino Energy LLC historical audited consolidated financial statements included elsewhere in this prospectus. Although we have taken measures to improve our internal control over financial reporting, we cannot assure you that additional material weaknesses that may result in a material misstatement of our financial statements will not occur in the future.

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

            We have no history operating as a publicly traded partnership. As a publicly traded partnership, we will incur significant legal, accounting and other expenses that we did not incur prior to this offering. In addition, the Sarbanes-Oxley Act of 2002, as well as rules implemented by the SEC and the NYSE, require publicly-traded entities to adopt various corporate governance practices that will further increase our costs. Before we are able to make distributions to our members, we must first pay or reserve cash for our expenses, including the costs of being a public company. As a result, the amount of cash we have available for distribution to our members will be affected by the costs associated with being a public company.

            Prior to this offering, we have not filed reports with the SEC. Following this offering, we will become subject to the public reporting requirements of the Exchange Act. We expect these rules and regulations to increase certain of our legal and financial compliance costs and to make activities more time-consuming and costly. For example, as a result of becoming a publicly-traded company, we are required to have at least three independent directors, create an audit committee and adopt policies regarding internal controls and disclosure controls and procedures, including the preparation of reports on internal controls over financial reporting. In addition, we will incur additional costs associated with our SEC reporting requirements.

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

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


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    Tax Risks

            In addition to reading the following risk factors, please read "Material Tax Consequences" for a more complete discussion of the expected material federal income tax consequences of owning and disposing of common units.

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

            The anticipated after-tax economic benefit of an investment in the common units depends largely on our being treated as a partnership for federal income tax purposes. We have not


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    requested, and do not plan to request, a ruling from the Internal Revenue Service, or IRS, on this or any other tax matter affecting us.

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

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

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

            Current law may change so as to cause us to be treated as a corporation for federal income tax purposes or otherwise subjecting us to entity-level taxation. Specifically, the present federal income tax treatment of publicly traded partnerships, including us, or an investment in our common units may be modified by administrative, legislative or judicial interpretation at any time. For example, at the federal level, legislation has been proposed that would eliminate partnership tax treatment for certain publicly traded partnerships. Although such legislation would not apply to us as currently proposed, it could be amended prior to enactment in a manner that does apply to us. Any modification to the federal income tax laws and interpretations thereof may or may not be applied retroactively. We are unable to predict whether any of these changes, or other proposals, will ultimately be enacted. Any such changes could negatively impact the value of an investment in our common units.


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

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

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


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

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

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

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

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

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


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    a tax liability in excess of the amount of cash you receive from the sale. Please read "Material Tax Consequences—Disposition of Common Units—Recognition of Gain or Loss" for a further discussion of the foregoing.

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

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


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

            Due to a number of factors, including our inability to match transferors and transferees of common units, we will adopt depreciation and amortization positions that may not conform to all aspects of existing Treasury Regulations. A successful IRS challenge to those positions could adversely affect the amount of tax benefits available to you. Our counsel is unable to opine as to the validity of such filing positions. It also could affect the timing of these tax benefits or the amount of gain from your sale of common units and could have a negative impact on the value of our common units or result in audit adjustments to your tax returns. Please read "Material Tax Consequences—Tax Consequences of Unit Ownership—Section 754 Election" for a further discussion of the effect of the depreciation and amortization positions we will adopt.

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

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


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

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


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

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

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

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

            We will be considered to have technically terminated for federal income tax purposes if there is a sale or exchange of 50% or more of the total interests in our capital and profits within a twelve-month period. For purposes of determining whether a technical tax termination has occurred, a sale or exchange of 50% or more of the total interests in our capital and profits could occur if, for example, Rhino Energy Holdings LLC, which will own approximately 83.2%85.2% of the total interests in our capital and profits immediately after the consummation of this offering, sells or exchanges a majority of the interests it owns in us within a period of twelve


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    months. For purposes of determining whether the 50% threshold has been met, multiple sales of the same unit will be counted only once. While we would continue our existence as a Delaware limited partnership, our technical termination would, among other things, result in the closing of our taxable year for all unitholders, which would result in us filing two tax returns (and our unitholders could receive two Schedules K-1) for one fiscal year and could result in a deferral of depreciation deductions allowable in computing our taxable income. In the case of a unitholder reporting on a taxable year other than a fiscal year ending December 31, the closing of our taxable year may also result in more than twelve months of our taxable income or loss being includable in his taxable income for the year of termination. A technical termination would not affect our classification as a partnership for federal income tax purposes, but instead, we would be treated as a new partnership for tax purposes. If treated as a new partnership, we must make new tax elections and could be subject to penalties if we are unable to determine that a technical termination occurred. The IRS has recently announced a relief procedure whereby if a publicly traded partnership that has technically terminated requests and the IRS grants special relief, among other things, the partnership will be required to provide only a single Schedule K-1 to unitholders for the tax years in which the termination occurs.


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

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

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

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


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    USE OF PROCEEDS

            Based on an assumed initial offering price of $20.00 per common unit, we expect to receive net proceeds of approximately $67.0$57.5 million from the sale of 3,750,0003,244,000 common units offered by this prospectus, after deducting the estimated underwriting discount and offering expenses payable by us, and a related capital contribution by our general partner of approximately $10.1 million to maintain its 2.0% general partner interest in us.

            We intend to use all of the net proceeds from this offering and the related capital contribution by our general partner to repay indebtedness outstanding under our credit agreement, which was incurred for working capital needs and the acquisitions of coal properties and mining equipment. We may reborrow any amounts repaid under our credit agreement. Upon application of the net proceeds from this offering as described herein,and the related capital contribution by our general partner, we will have $50.1$34.5 million of indebtedness outstanding under our credit agreement.

            On June 30, 2010, we amended our credit agreement. References to our credit agreement refer to the credit agreement as amended. Our credit agreement bears interest at either (1) LIBOR plus 3.0% to 3.5% per annum, depending on our leverage ratio, or (2) a base rate that is the sum of (i) the higher of (a) the prime rate, (b) the federal funds rate plus 0.5% or (c) LIBOR plus 1.0% and (ii) 1.5% to 2.0% per annum, depending on our leverage ratio. We incur letter of credit fees equal to the then applicable spread above LIBOR on the undrawn face amount of standby letters of credit 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 agreement at a rate of 0.5% per annum based on the unused portion of the facility. The credit agreement will mature in February 2013. Please read "Management's Discussion and Analysis of Financial Condition and Results of Operations—Liquidity and Capital Resources—Credit Agreement."

            The net proceeds from any exercise of the underwriters' option to purchase additional common units (approximately $10.5$9.1 million based on an assumed initial offering price of $20.00 per common unit, if exercised in full) will be used to reimburse Wexford for capital expenditures incurred with respect to the assets contributed to us. If the underwriters do not exercise their option to purchase additional common units, we will issue 562,500486,600 common units to Rhino Energy Holdings LLC at the expiration of the option period. If and to the extent the underwriters exercise their option to purchase additional common units, the number of units purchased by the underwriters pursuant to such exercise will be issued to the public and the remainder, if any, will be issued to Rhino Energy Holdings LLC. Accordingly, the exercise of the underwriters' option will not affect the total number of units outstanding or the amount of cash needed to pay the minimum quarterly distribution on all units. Please read "Underwriting."

            Affiliates of Raymond James & Associates, Inc. and RBC Capital Markets Corporation are lenders under our credit agreement and will receive their pro rata portion of the net proceeds from this offering and the related capital contribution by our general partner through the repayment of borrowings they have extended under the credit agreement.

            A $1.00 increase or decrease in the assumed initial public offering price of $20.00 per common unit would cause the net proceeds from this offering, after deducting the estimated underwriting discount and offering expenses payable by us, and the related capital contribution by our general partner, to increase or decrease, respectively, by approximately $3.5 million. In addition, we may also increase or decrease the number of common units we are offering. Each increase of 1.0 million common units offered by us, together with a concomitant $1.00 increase in the assumed public offering price to $21.00 per common unit, would increase net proceeds to us from this offering and the related capital contribution by our general partner by approximately $23.1 million. Similarly, each decrease of 1.0 million common units offered by us, together with a concomitant $1.00 decrease in the assumed initial offering price to $19.00 per common unit, would decrease the net proceeds to us from this offering and the related capital contribution by our general partner by approximately $21.2 million.


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    CAPITALIZATION

            The following table shows our capitalization as of March 31,June 30, 2010:

      on an actual basis for our predecessor, Rhino Energy LLC; and

      on a pro forma basis, to reflect the offering of our common units, the other transactions described under "Summary—The Transactions" and the application of the net proceeds from this offering and the related capital contribution by our general partner as described under "Use of Proceeds."

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



     As of March 31, 2010 
     As of June 30, 2010 


     Actual Pro Forma 
     Actual Pro Forma 


     (in thousands)
     
     (in thousands)
     

    Debt:

    Debt:

     

    Debt:

     

    Credit facility

     $117,020 $50,070 

    Credit facility

     $102,140 $34,507 

    Other debt

     6,813 6,813 

    Other debt

     6,314 6,314 
               

    Total debt

     123,833 56,883 

    Total debt

     108,454 40,821 
               

    Members'/partners' equity:

    Members'/partners' equity:

     

    Members'/partners' equity:

     

    Rhino Energy LLC

     143,467  

    Rhino Energy LLC

     150,609  

    Rhino Resource Partners LP:

     

    Rhino Resource Partners LP:

     

    Held by public:

     

    Held by public:

     
     

    Common units (1)

      31,188  

    Common units (1)

      27,983 

    Held by Wexford:

     

    Held by Wexford:

     
     

    Common units

      71,916  

    Common units

      78,955 
     

    Subordinated units

      103,104  

    Subordinated units

      106,939 
     

    General partner interest

      4,208  

    General partner interest

      4,365 

    Accumulated other comprehensive income

     
    1,477
     
    1,477
     

    Accumulated other comprehensive income

     
    1,477
     
    1,477
     
               
     

    Total members'/partners' equity

     144,944 211,894  

    Total members'/partners' equity

     152,086 219,719 
               
     

    Total capitalization (1)

     $268,777 $268,777  

    Total capitalization (1)

     $260,540 $260,540 
               

    (1)
    Each $1.00 increase or decrease in the assumed public offering price of $20.00 per common unit would increase or decrease, respectively, each of total partners' equity and total capitalization by approximately $3.5 million, after deducting the estimated underwriting discount and offering expenses payable by us. We may also increase or decrease the number of common units we are offering. Each increase of 1.0 million common units offered by us, together with a concomitant $1.00 increase in the assumed offering price to $21.00 per common unit, would increase total partners' equity and total capitalization by approximately $23.1 million. Similarly, each decrease of 1.0 million common units offered by us, together with a concomitant $1.00 decrease in the assumed offering price to $19.00 per common unit, would decrease total partners' equity and total capitalization by approximately $21.2 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.

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    DILUTION

            Dilution is the amount by which the offering price will exceed the net tangible book value per common unit after the offering. Assuming an initial public offering price of $20.00 per common unit, on a pro forma basis as of March 31,June 30, 2010, after giving effect to the offering of common units and the related transactions, our net tangible book value was approximately $208.9$216.8 million, or $8.25$8.57 per common unit. The pro forma net tangible book value excludes $2.1$2.0 million of deferred financing costs and $1.0$0.9 million of intangible assets and goodwill. Purchasers of our common units in this offering will experience substantial and immediate dilution in net tangible book value per common unit for financial accounting purposes, as illustrated in the following table.

    Assumed initial public offering price per common unit

       $20.00    $20.00 

    Net tangible book value per common unit before the offering (1)

     $6.58    $6.76   

    Increase in net tangible book value per common unit attributable to purchasers in the offering

     1.67    1.81   
              

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

       8.25    8.57 
          

    Immediate dilution in net tangible book value per common unit to purchasers in the offering (3)

       $11.75    $11.43 
          

    (1)
    Determined by dividing the net tangible book value of the contributed assets and liabilities by the number of units (8,647,000(9,153,000 common units, 12,397,000 subordinated units and the 2.0% general partner interest represented by 506,000 notional general partner units) to be issued to our general partner and its affiliates for their contribution of assets and liabilities to us. The number of units notionally represented by the 2.0% general partner interest is determined by multiplying the total number of units deemed to be outstanding (i.e., the total number of common and subordinated units outstanding divided by 98.0%) by the 2.0% general partner interest.
    (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 units (12,397,000 common units, 12,397,000 subordinated units and the 2.0% general partner interest represented by 506,000 notional general partner units). The number of units notionally represented by the 2.0% general partner interest is determined by multiplying the total number of units deemed to be outstanding (i.e., the total number of common and subordinated units outstanding divided by 98.0%) by the 2.0% general partner interest.
    (3)
    Each $1.00 increase or decrease in the assumed public offering price of $20.00 per common unit would increase or decrease, respectively, our pro forma net tangible book value by approximately $3.75$3.5 million, or approximately $0.32$0.28 per common unit, and dilution per common unit to investors in this offering by approximately $0.68$0.72 per common unit, after deducting the estimated underwriting discount and offering expenses payable by us. We may also increase or decrease the number of common units we are offering. An increase of 1.0 million common units offered by us, together with a concomitant $1.00 increase in the assumed offering price to $21.00 per common unit, would result in a pro forma net tangible book value of approximately $232.0$239.9 million, or $18.70$19.35 per common unit, and dilution per common unit to investors in this offering would be $12.12$12.59 per common unit. Similarly, a decrease of 1.0 million common units offered by us, together with a concomitant $1.00 decrease in the assumed public offering price to $19.00 per common unit, would result in an pro forma net tangible book value of approximately $188.0$195.6 million, or $15.13$15.78 per common unit, and dilution per common unit to investors in this offering would be $8.55$9.01 per common unit. 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.

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            The following table sets forth the number of units that we will issue and the total consideration contributed to us by our general partner and its affiliates and by the purchasers of our common units in this offering upon consummation of the transactions contemplated by this prospectus.prospectus:


     Units Total Consideration  Units Total Consideration 

     Number Percent Amount Percent  Number Percent Amount Percent 

    General partner and its affiliates (1)(2)

     21,550,000 85.2%$143,467,246 65.7% 22,056,000 87.2%$160,729,208 71.2%

    New investors

     3,750,000 14.8% 75,000,000 34.3% 3,244,000 12.8% 64,880,000 28.8%
                      

    Total

     25,300,000 100%$218,467,246 100% 25,300,000 100%$225,609,208 100%
                      

    (1)
    Upon the consummation of the transactions contemplated by this prospectus, our general partner and its affiliates will own 8,647,0009,153,000 common units, 12,397,000 subordinated units and a 2.0% general partner interest represented by 506,000 notional general partner units. The number of units notionally represented by the 2.0% general partner interest is determined by multiplying the total number of units deemed to be outstanding (i.e., the total number of common and subordinated units outstanding divided by 98.0%) by the 2.0% general partner interest.
    (2)
    The assets contributed by Wexford will be recorded at historical cost. The pro forma book value of the consideration provided by Wexford as of March 31,June 30, 2010 would have been approximately $179,228,919.$185.9 million.

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    CASH DISTRIBUTION POLICY AND RESTRICTIONS ON DISTRIBUTIONS

            You should read the following discussion of our cash distribution policy in conjunction with specific assumptions included in this section. In addition, you should read "Forward-Looking Statements" and "Risk Factors" for information regarding statements that do not relate strictly to historical or current facts and certain risks inherent in our business.

            For additional information regarding our historical and pro forma consolidated results of operations, you should refer to the audited historical consolidated financial statements as of December 31, 2008 and 2009 and for the years ended December 31, 2007, 2008 and 2009 and the unaudited historical condensed consolidated financial statements as of March 31,June 30, 2010 and for the threesix months ended March 31,June 30, 2009 and 2010 of Rhino Energy LLC and our unaudited pro forma condensed consolidated financial statements as of and for the year ended December 31, 2009 and as of and for the threesix months end March 31,June 30, 2010, included elsewhere in this prospectus.

    General

    Rationale for Our Cash Distribution Policy

            Our partnership agreement requires us to distribute all of our available cash each quarter. Our cash distribution policy reflects a judgment that our unitholders will be better served by our distributing rather than retaining our available cash. Our partnership agreement generally defines available cash as, for each quarter, cash generated from our business in excess of the amount of cash reserves established by our general partner to provide for the conduct of our business, to comply with applicable law, any of our debt instruments or other agreements or to provide for future distributions to our unitholders for any one or more of the next four quarters. Our available cash may also include, if our general partner so determines, all or any portion of the cash on hand on the date of determination of available cash for the quarter resulting from working capital borrowings made subsequent to the end of such quarter. Since our revenue and cash available for distribution will likely fluctuate over time as a result of changes in coal prices as well as other factors, the board of directors of our general partner expects to reserve from time to time all or a portion of any cash generated in excess of the amount sufficient to pay the full minimum quarterly distribution on all units, as a whole, to allow us to maintain and to gradually increase our quarterly cash distributions. We may also borrow to fund distributions in quarters when we generate less available cash than necessary to sustain or grow our cash distributions per unit. Because we are not subject to an entity-level federal income tax, we have more cash to distribute to our unitholders than would be the case were we subject to federal income tax.

    Limitations on Cash Distributions and Our Ability to Change Our Cash Distribution Policy

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

      Our cash distribution policy is subject to restrictions on distributions under our credit agreement. Our credit agreement contains financial tests and covenants that we must satisfy. These financial tests and covenants are described in "Management's Discussion and Analysis of Financial Condition and Results of Operations—Liquidity and Capital Resources—Credit Agreement." Should we be unable to satisfy these restrictions or if we

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        are otherwise in default under our credit agreement, we would be prohibited from making cash distributions notwithstanding our cash distribution policy.

      Our general partner will have the authority to establish cash reserves for the prudent conduct of our business and for future cash distributions to our unitholders, and the establishment of or increase in those reserves could result in a reduction in cash distributions from levels we currently anticipate pursuant to our stated cash distribution

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        policy. Our partnership agreement does not set a limit on the amount of cash reserves that our general partner may establish.



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

      While our partnership agreement requires us to distribute all of our available cash, our partnership agreement, including provisions requiring us to make cash distributions contained therein, may be amended. Our partnership agreement generally may not be amended during the subordination period without the approval of our public common unitholders. However, our partnership agreement can be amended with the consent of our general partner and the approval of a majority of the outstanding common units (including common units held by Wexford) after the subordination period has ended. At the closing of this offering, Wexford will own approximately 69.8%73.8% of the outstanding common units and all of our outstanding subordinated units. Please read "The Partnership Agreement—Amendment of the Partnership Agreement."

      Even if our cash distribution policy is not modified or revoked, the amount of distributions we pay under our cash distribution policy and the decision to make any distribution is determined by our general partner, taking into consideration the terms of our partnership agreement.

      Under Section 17-607 of the Delaware Act, we may not make a distribution if the distribution would cause our liabilities to exceed the fair value of our assets.

      We may lack sufficient cash to pay distributions to our unitholders due to cash flow shortfalls attributable to a number of operational, commercial or other factors as well as increases in our operating or selling, general and administrative expenses, principal and interest payments on our outstanding debt, tax expenses, working capital requirements and anticipated cash needs.

      If we make distributions out of capital surplus, as opposed to operating surplus, such distributions will result in a reduction in the minimum quarterly distribution and the target distribution levels. Please read "Provisions of Our Partnership Agreement Relating to Cash Distributions—Adjustment to the Minimum Quarterly Distribution and Target

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        Distribution Levels." We do not anticipate that we will make any distributions from capital surplus.

      Our ability to make distributions to our unitholders depends on the performance of our subsidiaries and their ability to distribute cash to us. The ability of our subsidiaries to make distributions to us may be restricted by, among other things, the provisions of existing and future indebtedness, applicable state partnership and limited liability company laws and other laws and regulations.

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    Our Ability to Grow is Dependent on Our Ability to Access External Expansion Capital

            Our partnership agreement requires us to distribute all of our available cash to our unitholders on a quarterly basis. As a result, we expect that we will rely primarily upon external financing sources, including commercial bank borrowings and the issuance of debt and equity securities, to fund any future expansion capital expenditures. To the extent we are unable to finance growth externally, our cash distribution policy will significantly impair our ability to grow. In addition, because we distribute all of our available cash, our growth may not be as fast as businesses that reinvest all of their available cash to expand ongoing operations. To the extent we issue additional units, the payment of distributions on those additional units may increase the risk that we will be unable to maintain or increase our per unit distribution level. There are no limitations in our partnership agreement or our credit agreement on our ability to issue additional units, including units ranking senior to the common units. The incurrence of additional commercial borrowings or other debt to finance our growth would result in increased interest expense, which in turn may impact the available cash that we have to distribute to our unitholders.

    Minimum Quarterly Distribution

            Upon the consummation of this offering, the board of directors of our general partner will establish a minimum quarterly distribution of $0.445 per unit for each complete quarter, or $1.78 per unit on an annualized basis, to be paid within 45 days after the end of each quarter. This equates to an aggregate cash distribution of $11.3 million per quarter, or $45.0 million per year, based on the number of common and subordinated units and 2.0% general partner interest to be outstanding immediately after completion of this offering. Our ability to make cash distributions equal to the minimum quarterly distribution pursuant to our cash distribution policy will be subject to the factors described above under "—General—Limitations on Cash Distributions and Our Ability to Change Our Cash Distribution Policy." The amount of available cash needed to pay the minimum quarterly distribution on all of the common units, subordinated units and 2.0% general partner interest to be outstanding immediately after this offering for one quarter and for four quarters is summarized in the table below:

     
      
     Distributions 
     
     Number of
    Units
     
     
     One Quarter Annualized 

    Common units

      12,397,000 $5,516,665 $22,066,660 

    Subordinated units

      12,397,000  5,516,665  22,066,660 

    General partner interest (1)

      506,000  225,170  900,680 
            
     

    Total

      25,300,000 $11,258,500 $45,034,000 
            

    (1)
    The number of units notionally represented by the 2.0% general partner interest is determined by multiplying the total number of units deemed to be outstanding (i.e., the total number of common and subordinated units outstanding divided by 98.0%) by the 2.0% general partner interest.

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            The preceding table assumes the underwriters have not exercised their option to purchase additional common units. If the underwriters do not exercise their option to purchase additional common units, we will issue 562,500486,600 common units to Rhino Energy Holdings LLC at the expiration of the option period. If and to the extent the underwriters exercise their option to purchase additional common units, the number of units purchased by the underwriters pursuant to such exercise will be sold to the public and the remainder, if any, will be issued to Rhino Energy Holdings LLC. Accordingly, the exercise of the underwriters' option will not affect the total number of units outstanding or the amount of cash needed to pay the minimum quarterly distribution on all units. Please read "Underwriting."


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            As of the date of this offering, our general partner will be entitled to 2.0% of all distributions that we make prior to our liquidation. Our general partner's initial 2.0% interest in these distributions may be reduced if we issue additional units in the future and our general partner does not contribute a proportionate amount of capital to us to maintain its initial 2.0% general partner interest.

            During the subordination period, before we make any quarterly distributions to our subordinated unitholders, our common unitholders are entitled to receive payment of the minimum quarterly distribution plus any arrearages in distributions from prior quarters. Please read "Provisions of Our Partnership Agreement Relating to Cash Distributions—Subordination Period." We cannot guarantee, however, that we will pay the minimum quarterly distribution on the common units in any quarter.

            We do not have a legal obligation to pay distributions at our minimum quarterly distribution rate or at any other rate except as provided in our partnership agreement. Our cash distribution policy is consistent with the terms of our partnership agreement, which requires that we distribute all of our available cash quarterly. Under our partnership agreement, available cash is generally defined to mean, for each quarter, cash generated from our business in excess of the amount of reserves established by our general partner to provide for the conduct of our business, to comply with applicable law, any of our debt instruments or other agreements or to provide for future distributions to our unitholders for any one or more of the next four quarters.

            Although holders of our common units may pursue judicial action to enforce provisions of our partnership agreement, including those related to requirements to make cash distributions as described above, our partnership agreement provides that any determination made by our general partner in its capacity as our general partner must be made in good faith and that any such determination will not be subject to any other standard imposed by the Delaware Act or any other law, rule or regulation or at equity. Our partnership agreement provides that, in order for a determination by our general partner to be made in "good faith," our general partner must believe that the determination is in our best interest. Please read "Conflicts of Interest and Fiduciary Duties."

            Our cash distribution policy, as expressed in our partnership agreement, may not be modified or repealed without amending our partnership agreement; however, the actual amount of our cash distributions for any quarter is subject to fluctuations based on the amount of cash we generate from our business and the amount of reserves our general partner establishes in accordance with our partnership agreement as described above.

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


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    for the period from the closing of this offering through September 30, 2010 based on the actual length of the period.

    Pro Forma and Forecasted Results of Operations and Cash Available for Distribution

            In this section, we present in detail the basis for our belief that we will be able to pay the minimum quarterly distribution on all of our common units and subordinated units and make the corresponding distributions on our 2.0% general partner interest for the twelve months ending JuneSeptember 30, 2011. We present a table, consisting of pro forma and forecasted results of operations and cash available for distribution for the year ended December 31, 2009, the twelve


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    months ended March 31,June 30, 2010 and the twelve months ending JuneSeptember 30, 2011. In the table that follows, we show our pro forma results of operations and the amount of cash available for distribution we would have had for the year ended December 31, 2009 and the twelve months ended March 31,June 30, 2010 based on our unaudited pro forma condensed consolidated statements of operations included elsewhere in this prospectus and our forecasted results of operations and the forecasted amount of cash available for distribution for the twelve months ending JuneSeptember 30, 2011 and the significant assumptions upon which this forecast is based.

            Our unaudited pro forma condensed consolidated financial statements are derived from the audited historical and the unaudited historical condensed consolidated financial statements of Rhino Energy LLC included elsewhere in this prospectus and our predecessor's accounting records, which are unaudited. Our unaudited pro forma condensed consolidated financial statements should be read together with "Selected Historical Consolidated and Pro Forma Condensed Consolidated Financial and Operating Data," "Management's Discussion and Analysis of Financial Condition and Results of Operations" and the audited historical consolidated financial statements of Rhino Energy LLC and the notes to those statements included elsewhere in this prospectus.

            We must generate approximately $45.0 million (or approximately $11.3 million per quarter) of available cash to pay the minimum quarterly distribution for four quarters on all of our common units and subordinated units that will be outstanding immediately after this offering and the corresponding distribution on our general partner interest. We did not, however, generate $45.0 million of available cash from operating surplus during the year ended December 31, 2009 or the twelve months ended March 31,June 30, 2010. The amount of available cash from operating surplus we generated with respect to those periods was approximately $33.4 million and $39.3$43.6 million, respectively. Asrespectively, or approximately $11.6 million and $1.5 million, respectively, less than the amount needed to pay the full minimum quarterly distributions on all units as a result, forwhole, including subordinated units. For those periods, we would have generated available cash sufficient to pay 100% of the minimum quarterly distribution on our common units, but only approximately 48.3%48.4% and 74.8%93.5%, respectively, of the minimum quarterly distribution on our subordinated units during those periods. We have not usedcalculated available cash on a quarter-by-quarter estimatesbasis for each quarter in the year ended December 31, 2009 andor the twelve months ended March 31,June 30, 2010 to determine if we would have generated available cash sufficient to pay the minimum quarterly distribution for each quarter during those periods.

            The following table also sets forth our calculation of forecasted cash available for distribution to our unitholders and general partner for the twelve months ending JuneSeptember 30, 2011. We forecast that our cash available for distribution generated during the twelve months ending JuneSeptember 30, 2011 will be approximately $74.8$77.9 million. This amount would be sufficient to pay the minimum quarterly distribution of $0.445 per unit on all of our common units and subordinated units and the corresponding distribution on our general partner's 2.0% general partner interest for each quarter in the four quarters ending JuneSeptember 30, 2011. Since


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    our revenue and cash available for distribution will likely fluctuate over time as a result of changes in coal prices as well as other factors, the board of directors of our general partner expects to reserve from time to time all or a portion of any cash generated in excess of the amount sufficient to pay the full minimum quarterly distribution on all units, as a whole, to allow us to maintain and to gradually increase our quarterly cash distributions.

            We are providing the financial forecast to supplement our pro forma and historical consolidated financial statements in support of our belief that we will have sufficient cash available to allow us to pay cash distributions on all of our common units and subordinated units and the corresponding distributionsdistribution on our general partner's 2.0% general partner interest for each quarter in the twelve months ending JuneSeptember 30, 2011 at the minimum quarterly distribution rate. Please read "—Significant Forecast Assumptions" for further information as to the assumptions we have made for the financial forecast. Please read "Management's Discussion and Analysis of Financial Condition and Results of Operations—Critical Accounting Policies and Estimates" for information as to the accounting policies we have followed for the financial forecast.


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            Our forecast reflects our judgment as of the date of this prospectus of conditions we expect to exist and the course of action we expect to take during the twelve months ending JuneSeptember 30, 2011. We believe that our actual results of operations will approximate those reflected in our forecast, but we can give no assurance that our forecasted results will be achieved. If our estimates are not achieved, we may not be able to pay distributions on our common units and subordinated units at the minimum quarterly distribution rate of $0.445 per unit each quarter (or $1.78 per unit on an annualized basis) or any other rate. The assumptions and estimates underlying the forecast are inherently uncertain and, though we consider them reasonable as of the date of this prospectus, are subject to a wide variety of significant business, economic, and competitive risks and uncertainties that could cause actual results to differ materially from those contained in the forecast, including, among others, risks and uncertainties contained in "Risk Factors." Accordingly, there can be no assurance that the forecast is indicative of our future performance or that actual results will not differ materially from those presented in the forecast. Inclusion of the forecast in this prospectus should not be regarded as a representation by any person that the results contained in the forecast will be achieved.

            We do not, as a matter of course, make public forecasts as to future sales, earnings or other results. However, we have prepared the following forecast to present the forecasted cash available for distribution to our unitholders and general partner during the forecasted period. The accompanying forecast was not prepared with a view toward complying with the guidelines established by the American Institute of Certified Public Accountants with respect to prospective financial information, but, in our view, was prepared on a reasonable basis, reflects the best currently available estimates and judgments, and presents, to the best of management's knowledge and belief, the expected course of action and our expected future financial performance. However, this information is not necessarily indicative of future results.

            Neither our independent auditors, nor any other independent accountants, have compiled, examined or performed any procedures with respect to the forecast contained herein, nor have they expressed any opinion or any other form of assurance on such information or its achievability, and assume no responsibility for, and disclaim any association with, the forecast. We do not undertake to release publicly after this offering any revisions or updates to the financial forecast or the assumptions on which our forecasted results of operations are based.


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    Rhino Resource Partners LP
    Cash Available for Distribution



     Pro Forma (1) Forecasted (1)(2) 
     Pro Forma (1) Forecasted (1)(2) 


     Year Ended
    December 31,
    2009
     Twelve Months
    Ended
    March 31,
    2010
     Twelve Months
    Ending
    June 30,
    2011
     
     Year Ended
    December 31,
    2009
     Twelve Months
    Ended
    June 30,
    2010
     Twelve Months
    Ending
    September 30,
    2011
     


     (in thousands, except average coal price)
     
     (in thousands, except average coal price)
     

    Operating Data:

    Operating Data:

      

    Operating Data:

      

    Coal produced in tons

    Coal produced in tons

      4,705 4,218 4,400 

    Coal produced in tons

      4,705 4,120 4,833 

    (Increase) decrease to coal inventory in tons

    (Increase) decrease to coal inventory in tons

      (34) (77) 241 

    (Increase) decrease to coal inventory in tons

      (34) (122) 108 

    Coal purchased in tons

    Coal purchased in tons

      2,027 1,567 115 

    Coal purchased in tons

      2,027 1,046 166 
                   

    Coal sales in tons

    Coal sales in tons

      6,699 5,708 4,757 

    Coal sales in tons

      6,699 5,045 5,106 

    Steam coal sales in tons—committed (3)

    Steam coal sales in tons—committed (3)

      6,277 5,270 3,239 

    Steam coal sales in tons—committed (3)

      6,277 4,510 3,158 

    Wgt. avg. steam coal sales price per ton—committed (3)

    Wgt. avg. steam coal sales price per ton—committed (3)

     $54.39 $54.58 $56.86 

    Wgt. avg. steam coal sales price per ton—committed (3)

     $54.39 $54.92 $60.40 

    Metallurgical coal sales in tons—committed (3)

    Metallurgical coal sales in tons—committed (3)

      354 363 391 

    Metallurgical coal sales in tons—committed (3)

      354 413 313 

    Wgt. avg. metallurgical coal sales price per ton—committed (3)

    Wgt. avg. metallurgical coal sales price per ton—committed (3)

     $162.57 $165.12 $127.09 

    Wgt. avg. metallurgical coal sales price per ton—committed (3)

     $162.57 $151.86 $115.51 

    Steam coal sales in tons—uncommitted

    Steam coal sales in tons—uncommitted

      68 65 808 

    Steam coal sales in tons—uncommitted

      68 64 1,235 

    Wgt. avg. steam coal sales price per ton—uncommitted

    Wgt. avg. steam coal sales price per ton—uncommitted

     $46.62 $45.74 $52.68 

    Wgt. avg. steam coal sales price per ton—uncommitted

     $46.62 $45.76 $52.37 

    Metallurgical coal sales in tons—uncommitted

    Metallurgical coal sales in tons—uncommitted

      n/a 10 319 

    Metallurgical coal sales in tons—uncommitted

      n/a 59 401 

    Wgt. avg. metallurgical coal sales price per ton—uncommitted

    Wgt. avg. metallurgical coal sales price per ton—uncommitted

      n/a $85.00 $110.00 

    Wgt. avg. metallurgical coal sales price per ton—uncommitted

      n/a $121.97 $105.00 

    Financial Data:

    Financial Data:

      

    Financial Data:

      

    Coal sales revenue—committed (3)

     $398,595 $347,212 $233,873 

    Coal sales revenue—uncommitted

      3,157 3,852 77,604 

    Other coal sales revenue (4)

      5,050 4,997 1,305 

    Coal revenue—committed (3)

    Coal revenue—committed (3)

     $398,595 $310,005 $226,921 

    Coal revenue—uncommitted

    Coal revenue—uncommitted

      3,157 10,076 106,712 

    Other coal revenue (4)

    Other coal revenue (4)

      5,050 4,636 1,085 

    Other revenues (5)

    Other revenues (5)

      12,988 13,626 15,195 

    Other revenues (5)

      12,988 14,009 13,219 
                   
     

    Total revenues

     $419,790 $369,686 $327,977  

    Total revenues

     $419,790 $338,725 $347,937 
                   

    Costs and expenses:

    Costs and expenses:

      

    Costs and expenses:

      

    Cost of operations (exclusive of depreciation, depletion and amortization shown separately below)

     $336,335 $284,370 $220,095 

    Cost of operations (exclusive of depreciation, depletion and amortization shown separately below)

     $336,335 $257,009 $234,994 

    Freight and handling

      3,990 3,725 3,907 

    Freight and handling

      3,990 3,458 4,497 

    Depreciation, depletion and amortization (6)

      36,279 34,070 36,345 

    Depreciation, depletion and amortization (6)

      36,279 32,210 36,620 

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

      16,754 16,056 15,482 

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

      16,754 15,369 15,614 

    Incremental selling, general and administrative

        3,000 

    Incremental selling, general and administrative

        3,000 

    Loss on sale of assets

      1,710 1,709  

    Loss on sale of assets

      1,710 375  
                   
     

    Total costs and expenses

     $395,069 $339,930 $278,829  

    Total costs and expenses

     $395,069 $308,422 $294,725 
                   

    Income from operations

    Income from operations

     $24,721 $29,756 $49,148 

    Income from operations

     $24,721 $30,304 $53,212 

    Interest and other income (expense):

    Interest and other income (expense):

      

    Interest and other income (expense):

      

    Interest expense

      (4,291) (4,113) (3,803)

    Interest expense

      (4,271) (3,255) (3,664)

    Interest income

      154 75  

    Interest income

      154 103  

    Other income (expense)

      (83) (83)  

    Other income (expense)

      (83) (83)  

    Equity in net income of unconsolidated affiliate

      893 806 8,705 

    Equity in net income of unconsolidated affiliate

      893 1,574 8,915 
                   

    Net income

    Net income

     $21,394 $26,441 $54,049 

    Net income

     $21,413 $28,643 $58,463 
                   

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     Pro Forma (1) Forecasted (1)(2) 
     Pro Forma (1) Forecasted (1)(2) 


     Year Ended
    December 31,
    2009
     Twelve Months
    Ended
    March 31,
    2010
     Twelve Months
    Ending
    June 30,
    2011
     
     Year Ended
    December 31,
    2009
     Twelve Months
    Ended
    June 30,
    2010
     Twelve Months
    Ending
    September 30,
    2011
     


     (in thousands, except distributions per unit)
     
     (in thousands, except distributions per unit)
     

    Net income

    Net income

     $21,394 $26,441 $54,049 

    Net income

     $21,413 $28,643 $58,463 
                   

    Plus:

    Plus:

      

    Plus:

      

    Depreciation, depletion and amortization

      36,279 34,070 36,345 

    Depreciation, depletion and amortization

      36,279 32,210 36,620 

    Interest expense

      4,291 4,113 3,803 

    Interest expense

      4,271 3,255 3,664 
                   

    EBITDA (6)

    EBITDA (6)

     $61,964 $64,623 $94,197 

    EBITDA (6)

     $61,964 $64,108 $98,747 
                   

    Less:

    Less:

      

    Less:

      

    Cash interest expense

      (4,291) (4,113) (2,681)

    Cash interest expense

      (4,271) (3,255) (2,254)

    Equity in net income of unconsolidated affiliate (7)

      (893) (806)  

    Equity in net income of unconsolidated affiliate (7)

      (893) (1,574)  

    Maintenance capital expenditures (8)

      (23,393) (20,356) (16,686)

    Maintenance capital expenditures (8)

      (23,393) (15,699) (18,614)

    Expansion capital expenditures (8)

      (6,264) (4,973) (46,092)

    Expansion capital expenditures (8)

      (6,264) (6,573) (29,611)

    Plus:

    Plus:

      

    Plus:

      

    Borrowings or cash on hand for expansion capital expenditures (8)

      6,264 4,973 46,092 

    Borrowings or cash on hand for expansion capital expenditures (8)

      6,264 6,573 29,611 
                   

    Cash available for distribution

    Cash available for distribution

     $33,387 $39,349 $74,831 

    Cash available for distribution

     $33,406 $43,579 $77,879 
                   

    Implied cash distributions based on the minimum quarterly distribution per unit:

    Implied cash distributions based on the minimum quarterly distribution per unit:

      

    Implied cash distributions based on the minimum quarterly distribution per unit:

      

    Annualized minimum quarterly distribution per unit

     $1.78 $1.78 $1.78 

    Annualized minimum quarterly distribution per unit

     $1.78 $1.78 $1.78 

    Distribution to common unitholders

     $22,067 $22,067 $22,067 

    Distribution to common unitholders

     $22,067 $22,067 $22,067 

    Distribution to subordinated unitholder

      22,067 22,067 22,067 

    Distribution to subordinated unitholder

      22,067 22,067 22,067 

    Distribution to general partner

      901 901 901 

    Distribution to general partner

      901 901 901 
                   
     

    Total distributions (9)

     $45,034 $45,034 $45,034  

    Total distributions (9)

     $45,034 $45,034 $45,034 
                   

    Excess (shortfall)

    Excess (shortfall)

     $(11,647)$(5,685)$29,797 

    Excess (shortfall)

     $(11,628)$(1,455)$32,845 
                   

    (1)
    In May 2008, we entered into a joint venture, Rhino Eastern LLC, with an affiliate of Patriot that acquired the Rhino Eastern mining complex, which commenced production in August 2008. We have a 51% membership interest in, and serve as manager for, the joint venture.


    We account for the results of operations for the joint venture using the equity method. Please read "Management's Discussion and Analysis of Financial Condition and Results of Operations—Critical Accounting Policies and Estimates." Using the equity method, we recognize our proportionate share of the joint venture's net income as a single component of other income and include it in "Equity in net income of unconsolidated affiliate." As such, the operating data do not include data with respect to the Rhino Eastern mining complex. The financial data reflect the results of operations for the joint venture only in our presentation and analyses of net income and EBITDA and only with respect to our 51% membership interest in the joint venture.

    (2)
    The forecasted column is based on the assumptions set forth in "—Significant Forecast Assumptions" below. Please see "—Quarterly Forecast Information" for forecasted results of operations and cash available for distribution presented on a quarter-by-quarter basis.

    (3)
    Represents coal sold on a committed basis for the year ended December 31, 2009 and the twelve months ended March 31,June 30, 2010, in each case, on a pro forma basis, and coal committed for sale for the twelve months ending JuneSeptember 30, 2011.

    (4)
    Other coal revenues consist of coal quality adjustments and transportation revenue.

    (5)
    Other revenues consist of limestone sales, coal handling, royalties, contract mining and rental income.

    (6)
    Please read "Selected Historical Consolidated and Pro Forma Condensed Consolidated Financial and Operating Data—Non-GAAP Financial Measure."


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    (7)
    According to the terms of the joint venture agreement for Rhino Eastern LLC, the joint venture is to distribute all available funds to the members. The amount of available funds is determined by a committee comprised of two Rhino representatives and two Patriot representatives. That same committee will determine the timing and amount of cash distributions by the joint venture. To date, the joint venture, which commenced production in August 2008, has not made any cash distributions. However, as a result of the advancement of the joint venture operations past a development and rehabilitation stage and into a period of more consistent operations, our continuing to expand production and favorable metallurgical coal prices, we forecast a substantial increase in net income of our joint

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      venture for the forecast period, and we estimate that forecasted cash available for distribution resulting from the joint venture will approximate our forecasted equity interest in net income of the joint venture.



    (8)
    Historically, we have not made a distinction between maintenance capital expenditures and expansion capital expenditures. For purposes of this presentation, however, we have evaluated our capital expenditures for the year ended December 31, 2009 and the twelve months ended March 31,June 30, 2010 to determine which of them would have been classified as maintenance capital expenditures versus expansion capital expenditures, in accordance with our partnership agreement, at the time they were made. Based on this evaluation, we estimate that our maintenance capital expenditures for the year ended December 31, 2009 and the twelve months ended March 31,June 30, 2010 would have been $23.4 million and $20.6$15.7 million, respectively, and our expansion capital expenditures for the year ended December 31, 2009 and the twelve months ended March 31,June 30, 2010 would have been $6.3 million and $5.0$6.6 million, respectively. The amount of our actual maintenance capital expenditures may differ substantially from period to period, which could cause similar fluctuations in the amounts of operating surplus, adjusted operating surplus and available cash for distribution to our unitholders if we subtracted actual maintenance capital expenditures from operating surplus. To eliminate these fluctuations, our partnership agreement requires that an estimate of the maintenance capital expenditures necessary to maintain our operating capacity (as opposed to amounts actually spent) be subtracted from operating surplus each quarter. The $16.7$18.6 million of maintenance capital expenditures for the forecasted twelve months ending JuneSeptember 30, 2011 represents estimated maintenance capital expenditures as defined in our partnership agreement. The amount of estimated maintenance capital expenditures deducted from operating surplus is subject to review and change by the board of directors of our general partner at least once a year, provided that any change must be approved by the conflicts committee. Our partnership agreement does not cap the amount of maintenance capital expenditures that our general partner may estimate. We estimate that our expansion capital expenditures for the twelve months ending JuneSeptember 30, 2011 will be approximately $46.1$29.6 million. We expect to fund such expenditures with borrowings under our credit agreement. Please read "Provisions of Our Partnership Agreement Relating to Cash Distributions—Capital Expenditures" for a further discussion of maintenance capital expenditures and expansion capital expenditures.

    (9)
    Represents the amount that would be required to pay distributions for four quarters at our minimum quarterly distribution rate of $1.78 per unit on all of the common and subordinated units that will be outstanding immediately following this offering and the related distributions on our general partner's 2.0% general partner interest.

    Significant Forecast Assumptions

            The forecast has been prepared by and is the responsibility of our management. Our forecast reflects our judgment as of the date of this prospectus of conditions we expect to exist and the course of action we expect to take during the twelve months ending JuneSeptember 30, 2011. While the assumptions disclosed in this prospectus are not all-inclusive, the assumptions listed are those that we believe are significant to our forecasted results of operations. We believe we have a reasonable objective basis for these assumptions. We believe our actual results of operations will approximate those reflected in our forecast, but we can give no assurance that our forecasted results will be achieved. There will likely be differences between our forecast and the actual results, and those differences could be material. If the forecast is not achieved, we may not be able to pay cash distributions on our common units at the minimum distribution rate or at all.

            Production and Revenues. We forecast that our total revenues for the twelve months ending JuneSeptember 30, 2011 will be approximately $328.0$347.9 million, as compared to approximately $419.8 million and $369.7$338.7 million, in each case on a pro forma basis, for the year ended December 31, 2009 and the twelve months ended March 31,June 30, 2010, respectively. Our forecast is based primarily on the following assumptions:

      We estimate that, excluding the joint venture, Rhino Eastern LLC, we will produce approximately 4.44.8 million tons of coal for the twelve months ending JuneSeptember 30, 2011,

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        as compared to approximately 4.7 million tons and 4.24.1 million tons we produced for the year ended December 31, 2009 and the twelve months ended March 31,June 30, 2010, respectively, in each case on a pro forma basis. This volume decrease is primarily due to a decrease in production from our Central Appalachia operations. Production from alleach of our coal operations for the forecasted period is expected to decrease from or remain substantially consistent fromwith the year ended December 31, 2009 andbut increase from or remain substantially consistent with the twelve months ended March 31,June 30, 2010, to the forecasted period.in each case on a pro forma basis. Our Central Appalachia operations are expected to decrease production toproduce approximately 1.92.1 million tons in the forecasted period, a decrease from approximately 2.3 million


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          tons in the year ended December 31, 2009 and an increase from approximately 1.9 million tons in the twelve months ended March 31,June 30, 2010, in each case on a pro forma basis, as abasis. These changes are the result of idling several of our less profitable surface mines.mines in 2009, offset by increasing production of metallurgical coal from our Mine 28 in the forecasted period. Our Northern Appalachia operations are forecasted to remain substantially constant,consistent, with production of approximately 2.12.2 million tons in the forecasted period versus approximately 2.2 million tons in the year ended December 31, 2009 and approximately 2.12.0 million tons in the twelve months ended March 31,June 30, 2010, in each case on a pro forma basis. The operation in our Other segment currently producing coal, McClane Canyon mine, is expected to increasedecrease production slightly, from approximately 0.3 million tons in the year ended December 31, 2009 and approximately 0.2 million tons in the twelve months ended March 31,June 30, 2010, in each case on a pro forma basis, to approximately 0.4less than 0.1 million tons for the twelve months ending JuneSeptember 30, 2011, as we plan to temporarily idle this operation as we build and permit a rail loadout. However, we forecast that the operations in our Other segment are expected to increase production to approximately 0.5 million tons for the twelve months ending September 30, 2011, due to the expected acquisition of mining assets in Utah.Utah in August 2010, which we expect will begin production in late 2010. Our coal production could vary significantly from the foregoing assumption based on numerous factors, many of which are beyond our control.

        We estimate that, excluding results from the joint venture, we will sell approximately 4.85.1 million tons of coal, including approximately 0.20.1 million tons from inventory and approximately 0.10.2 million tons of purchased coal, for the twelve months ending JuneSeptember 30, 2011, as compared to approximately 6.7 million tons for the year ended December 31, 2009 and approximately 5.75.0 million tons for the twelve months ended March 31,June 30, 2010, in each case on a pro forma basis. ThisThe volume decrease from the year ended December 31, 2009 is primarily due to a decrease in purchased coal from approximately 2.0 million tons for the year ended December 31, 2009, and approximately 1.6 million tons for the twelve months ended March 31, 2010, in each case on a pro forma basis, to approximately 0.10.2 million tons for the twelve months ending September 30, 2011. Tons of coal sold is expected to increase slightly in the forecasted period as compared to the twelve months ended June 30, 2011.2010, on a pro forma basis, as the decrease in purchased coal from 1.0 million tons in the twelve months ended June 30, 2010, on a pro forma basis, to 0.2 million tons in the forecasted period is offset by an increase of production from 4.1 million tons in the twelve months ended June 30, 2010, on a pro forma basis, to 4.8 million tons in the twelve months ending September 30, 2011, as well as a sell-off of inventory of 0.1 million tons in the forecasted period as compared to a build-up of inventory of 0.1 million tons in the twelve months ended June 30, 2010, on a pro forma basis.

        We estimate that, excluding results from the joint venture, our coal revenues per ton will be $65.76$65.55 for the twelve months ending JuneSeptember 30, 2011, as compared to $59.98 for the year ended December 31, 2009 and $61.54$63.48 for the twelve months ended March 31,June 30, 2010, in each case on a pro forma basis. This increase is primarily due to supply contracts executed in 2008 at favorable prices and the sale of a greater quantity of metallurgical coal, which sells at a premium per ton to steam coal.



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          As of July 13,August 23, 2010, excluding results from the joint venture, we have commitments to sell approximately 3.63.5 million tons, or approximately 76%68% of our forecasted sales, during the forecasted period. Our committed sales tons include approximately 3.2 million tons of steam coal, committed at a weighted average price per ton of $56.86$60.40, and approximately 0.40.3 million tons of metallurgical coal, committed at a weighted average price per ton of $127.09.$115.51.

          Excluding results from the joint venture, we are also forecasting to sell approximately 1.11.6 million tons, or approximately 24%32% of our forecasted sales during the forecasted period, for which we do not currently have executed supply contracts. Our uncommitted sales tons include approximately 0.81.2 million tons of steam coal, which we project will sell for a weighted average price per ton of $52.68$52.37 and approximately 0.30.4 million tons of high-vol and mid-vol metallurgical coal, which we project will sell for a weighted average price per ton of $110.00.$105.00. Our uncommitted steam coal sales for the forecasted period include approximately 0.5 million tons of steam coal we expect to produce and sell from the acquisition of mining assets in Utah, which we project will sell for a weighted average price per ton of $44.21. Our estimated weighted average sales price for our uncommitted tons assumes that we will be successful in selling these tons at prices that reflect management's current estimates of market conditions and pricing trends.

                Actual results per ton could vary significantly from the foregoing assumptions if we are unable to deliver coal pursuant to our contracts, if a number of our customers are unable to


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          satisfy their contractual obligations or if we are incorrect in our pricing or volume assumptions for uncommitted sales.

              As of July 22, 2010, one of our coal supply contracts relating to sales commitments for our estimated coal production through 2014 contained provisions that allow for the purchase price to be renegotiated at periodic intervals. We are currently renegotiating the purchase price pursuant to this price re-opener provision. If we fail to agree on a new price on or prior to October 1, 2010, this coal supply contract will terminate. If this contract terminates, our estimates of coal sales tons and total coal sales revenue for the twelve months ending June 30, 2011 will remain the same in all material respects. Please read "Risk Factors—Risks Inherent in Our Business—The assumptions underlying our forecast of cash available for distribution included in "Cash Distribution Policy and Restrictions on Distributions" are inherently uncertain and subject to significant business, economic, financial, regulatory and competitive risks and uncertainties that could cause cash available for distribution to differ materially from those estimated." and "—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."

              Cost of Operations. We forecast our cost of operations, excluding the cost of purchased coal and results from the joint venture, will be approximately $214.0$226.0 million for the twelve months ending JuneSeptember 30, 2011, as compared to approximately $227.2 million for the year ended December 31, 2009 and approximately $201.7$202.7 million for the twelve months ended March 31,June 30, 2010, in each case on a pro forma basis. Cost of operations primarily includes the cost of labor and benefits, operating supplies, equipment maintenance, rental and lease cost of equipment, royalties, taxes and transportation costs. The decrease in cost of operations for the forecasted period as compared to the year ended December 31, 2009, on a pro forma basis, is attributable primarily to decreasedthe projected decrease in the cost of operating supplies and the rental and lease expense related to our mining equipment, partially offset by an increase in royalties related to the increase in coal revenues per ton sold. The increase in cost of operations for the forecasted period as compared to the twelve months ended June 30, 2010, on a pro forma basis, is attributable primarily to increased coal production for the forecasted period as compared to production in the twelve months ended June 30, 2010, on a pro forma basis.

              We forecast our cost of purchased coal will be approximately $9.0 million for the forecasted period as compared to approximately $109.1 million for the year ended December 31, 2009 and approximately $54.3 million for the twelve months ended March 31,June 30, 2010, in each case on a pro forma basis. This decrease is attributable primarily to approximately 0.2 million tons of purchased coal in the forecast period as compared to approximately 2.0 million tons in the year ended December 31, 2009 and approximately 1.0 million tons in the twelve months ended June 30, 2010, in each case on a pro forma basis.


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      We forecast that our cost of operations, including the cost of purchased coal, per ton for the twelve months ending JuneSeptember 30, 2011 will be $46.27,$46.02, as compared to $50.21 for the year ended December 31, 2009 and $47.27$50.95 for the twelve months ended March 31,June 30, 2010, in each case on a pro forma basis. This decrease is attributable primarily to cost cutting measures put into effect in 2009 and continued in the first quarterhalf of 2010, and an increase in coal sold out of inventory, a decrease in the volume and cost of purchased coal and a decrease in rental and lease expense related to our mining equipment in the forecasted period as compared to the year ended December 31, 2009 and the twelve months ended March 31,June 30, 2010, in each case on a pro forma basis. Our forecasted cost of operations could vary significantly because of the large number of variables taken into consideration, many of which are beyond our control.

              We forecast our cost of purchased coal will be approximately $6.1 million for the forecasted period as compared to approximately $109.1 million for the year ended December 31, 2009 and approximately $82.7 million for the twelve months ended March 31, 2010, in each case on a pro forma basis. This decrease is attributable primarily to approximately 0.1 million tons of purchased coal in the forecast period as compared to approximately 2.0 million tons in the year ended December 31, 2009 and approximately 1.6 million tons in the twelve months ended March 31, 2010, in each case on a pro forma basis.

              Depreciation, Depletion and Amortization. We forecast depreciation, depletion and amortization expense to be approximately $36.3$36.6 million for the twelve months ending JuneSeptember 30, 2011, as compared to approximately $36.3 million for the year ended December 31, 2009 and approximately $34.1$32.2 million for the twelve months ended March 31,June 30, 2010, in each case on a pro forma basis. The increase in depreciation, depletion and amortization expense of approximately $2.2$0.3 million in the forecast period as compared to the year ended December 31, 2009, on a pro forma basis, is due to a decrease in depreciation expense of approximately $1.0 million, offset by an increase in depletion expense of approximately $0.4 million and an increase in amortization expense of approximately $0.9 million. The increase in depreciation, depletion and amortization expense of approximately $4.4 million in the forecast period as compared to the twelve months ended March 31,June 30, 2010, on a pro forma basis, is due to an increase in depreciation expense of approximately $0.3$1.1 million, an increase in depletion expense of


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      approximately $0.5$0.8 million and an increase in amortization expense of approximately $1.4$2.5 million.

              Selling, General and Administrative. We forecast selling, general and administrative expenses to be approximately $18.5$18.6 million for the twelve months ending JuneSeptember 30, 2011, as compared to approximately $16.8 million for the year ended December 31, 2009, and approximately $16.1$15.4 million for the twelve months ended March 31,June 30, 2010, in each case on a pro forma basis. The forecasted selling, general and administrative expenses include wage increases, bonuses payable to certain executive officers upon the consummation of our initial public offering, inflationary increases in employee benefits and incremental expenses associated with being a publicly traded partnership of approximately $3.0 million.

              Acquisition of Mining Assets in Utah. In August 2010, we completed the acquisition of certain mining assets in Emery and Carbon Counties, Utah, from which we expect to begin production in late 2010. During the twelve months ending September 30, 2011, we expect to produce and sell 0.5 million tons of steam coal from these assets, for which we do not currently have executed supply contracts. We forecast we will generate approximately $1.0 million of income from operations and $3.4 million of EBITDA from these assets during the forecasted period on $20.1 million of revenue.

      Financing. We forecast interest expense of approximately $3.8$3.7 million for the twelve months ending JuneSeptember 30, 2011, as compared to approximately $4.3 million for the year ended December 31, 2009 and approximately $4.1$3.3 million for the twelve months ended March 31,June 30, 2010, in each case on a pro forma basis. Our total debt balance as of December 31, 2009, and March 31,June 30, 2010, in each case on a pro forma basis, was approximately $55.2$54.5 million and approximately $56.9


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      $40.8 million, respectively. Our interest expense for the twelve months ending JuneSeptember 30, 2011 is based on the following assumptions:following:

              Equity in net income of unconsolidated affiliate.    We forecast that our share of net income of our unconsolidated affiliate, a joint venture that owns the Rhino Eastern mining complex, will be approximately $8.7$8.9 million for the twelve months ending JuneSeptember 30, 2011, as compared to approximately $0.9 million and $0.8$1.6 million, in each case on a pro forma basis, for the year ended December 31, 2009 and the twelve months ended March 31,June 30, 2010, respectively. Our forecast is based on the following assumptions:


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              Capital Expenditures. We forecast capital expenditures for the twelve months ending JuneSeptember 30, 2011 based on the following assumptions:


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              Regulatory, Industry and Economic Factors. We forecast our results of operations for the twelve months ending JuneSeptember 30, 2011 based on the following assumptions related to regulatory, industry and economic factors:


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        No major adverse change in the coal markets in which we operate resulting from supply or production disruptions, reduced demand for our coal or significant changes in the market prices of coal.

        No material changes to market, regulatory and overall economic conditions.

      Quarterly Forecast Information

              The following table presents our forecasted results of operations and cash available for distribution on a quarter-by-quarter basis for the forecast period. The following forecast reflects our judgment as of the date of this prospectus of conditions we expect to exist and the course of action we expect to take for the twelve months ending JuneSeptember 30, 2011. Please see "—Significant Forecast Assumptions." The assumptions and estimates underlying the forecast for the twelve months ending JuneSeptember 30, 2011 are inherently uncertain, and estimating the precise quarter in which each revenue and expense will be recognized increases the level of uncertainty of the quarterly forecast information. Accordingly, there can be no assurance that actual quarter-by-quarter results will not differ materially from the quarter-by-quarter forecast information presented below. However, to the extent that a shortfall were to occur during a quarter in the forecast period, we believe we would be able to make working capital borrowings to pay distributions in such quarter, and would likely be able to repay such borrowings in a subsequent quarter, because we believe the total cash available for distribution for the forecast period will be more than sufficient to pay the aggregate minimum quarterly distribution to all unitholders and the corresponding distribution to our general partner for the forecast period.


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      Rhino Resource Partners LP
      Quarterly Forecast Information


       Forecasted 


       Forecasted 
       Three Months Ending  
       


       Three Months Ending  
       
       Twelve Months
      Ending
      September 30,
      2011
       


       September 30,
      2010
       December 31,
      2010
       March 31,
      2011
       June 30,
      2011,
       Twelve Months
      Ending June 30,
      2011
       
       December 31,
      2010
       March 31,
      2011
       June 30,
      2011,
       September 30,
      2011
       


       (in thousands, except average coal price)
       
       (in thousands, except average coal price)
       

      Operating Data:

      Operating Data:

       

      Operating Data:

       

      Coal produced in tons

      Coal produced in tons

       937 1,006 1,220 1,237 4,400 

      Coal produced in tons

       1,064 1,228 1,269 1,272 4,833 

      (Increase) decrease to coal inventory in tons

      (Increase) decrease to coal inventory in tons

       109 128 5 (1) 241 

      (Increase) decrease to coal inventory in tons

       64 24 1 20 108 

      Coal purchased in tons

      Coal purchased in tons

       55 60   115 

      Coal purchased in tons

       46 45 45 30 166 
                             

      Coal sales in tons

      Coal sales in tons

       1,101 1,194 1,225 1,236 4,757 

      Coal sales in tons

       1,173 1,297 1,314 1,322 5,106 

      Steam coal sales in tons—committed

      Steam coal sales in tons—committed

       970 968 650 650 3,239 

      Steam coal sales in tons—committed

       986 749 749 674 3,158 

      Wgt. avg. steam coal sales price per ton—committed

      Wgt. avg. steam coal sales price per ton—committed

       $54.70 $54.65 $60.08 $60.15 $56.86 

      Wgt. avg. steam coal sales price per ton—committed

       $56.28 $61.74 $61.81 $63.39 $60.40 

      Metallurgical coal sales in tons—committed

      Metallurgical coal sales in tons—committed

       131 148 53 60 391 

      Metallurgical coal sales in tons—committed

       148 53 60 53 313 

      Wgt. avg. metallurgical coal sales price per ton—committed

      Wgt. avg. metallurgical coal sales price per ton—committed

       $137.69 $138.64 $96.71 $102.13 $127.09 

      Wgt. avg. metallurgical coal sales price per ton—committed

       $138.53 $93.71 $96.88 $93.71 $115.51 

      Steam coal sales in tons—uncommitted

      Steam coal sales in tons—uncommitted

        51 377 380 808 

      Steam coal sales in tons—uncommitted

       32 361 379 463 1,235 

      Wgt. avg. steam coal sales price per ton—uncommitted

      Wgt. avg. steam coal sales price per ton—uncommitted

       n/a $44.50 $53.78 $52.70 $52.68 

      Wgt. avg. steam coal sales price per ton—uncommitted

       $42.50 $53.43 $52.11 $52.42 $52.37 

      Metallurgical coal sales in tons—uncommitted

      Metallurgical coal sales in tons—uncommitted

        27 146 146 319 

      Metallurgical coal sales in tons—uncommitted

       8 134 126 134 401 

      Wgt. avg. metallurgical coal sales price per ton—uncommitted

      Wgt. avg. metallurgical coal sales price per ton—uncommitted

       n/a $110.00 $110.00 $110.00 $110.00 

      Wgt. avg. metallurgical coal sales price per ton—uncommitted

       $105.00 $105.00 $105.00 $105.00 $105.00 

      Financial Data:

      Financial Data:

       

      Financial Data:

       

      Coal sales revenue—committed

      Coal sales revenue—committed

       $71,049 $73,412 $44,157 $45,256 $233,873 

      Coal sales revenue—committed

       $75,988 $51,188 $52,130 $47,615 $226,921 

      Coal sales revenue—uncommitted

      Coal sales revenue—uncommitted

        5,263 36,276 36,065 77,604 

      Coal sales revenue—uncommitted

       2,137 33,330 32,978 38,267 106,712 

      Other coal sales revenue

      Other coal sales revenue

       303 322 330 350 1,305 

      Other coal sales revenue

       266 325 329 164 1,085 

      Other revenues

      Other revenues

       4,415 4,432 3,373 2,974 15,195 

      Other revenues

       4,301 3,238 2,839 2,841 13,219 
                             
       

      Total revenues (1)

       $75,767 $83,430 $84,135 $84,645 $327,977  

      Total revenues (1)

       $82,692 $88,081 $88,276 $88,887 $347,937 
                             

      Costs and expenses:

      Costs and expenses:

       

      Costs and expenses:

       

      Cost of operations (exclusive of depreciation, depletion and amortization shown separately below)

       $53,276 $56,720 $55,306 $54,792 $220,095 

      Cost of operations (exclusive of depreciation, depletion and amortization shown separately below)

       $56,123 $60,106 $59,077 $59,688 $234,994 

      Freight and handling

       644 839 1,141 1,283 3,907 

      Freight and handling

       708 1,138 1,283 1,368 4,497 

      Depreciation, depletion and amortization

       9,006 8,898 9,264 9,177 36,345 

      Depreciation, depletion and amortization

       8,932 9,300 9,130 9,259 36,620 

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

       3,784 3,778 4,027 3,894 15,482 

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

       3,779 4,026 3,893 3,915 15,614 

      Incremental selling, general and administrative

       750 750 750 750 3,000 

      Incremental selling, general and administrative

       750 750 750 750 3,000 

      Loss on sale of assets

            

      Loss on sale of assets

            
                             
       

      Total costs and expenses (1)

       $67,460 $70,985 $70,488 $69,896 $278,829  

      Total costs and expenses (1)

       $70,292 $75,320 $74,133 $74,980 $294,725 
                             

      Income from operations

      Income from operations

       $8,307 $12,444 $13,647 $14,749 $49,148 

      Income from operations

       $12,400 $12,761 $14,143 $13,907 $53,212 

      Interest and other income (expense):

      Interest and other income (expense):

       

      Interest and other income (expense):

       

      Interest expense

       (909) (798) (951) (1,145) (3,803)

      Interest expense

       (776) (867) (982) (1,039) (3,664)

      Interest income

            

      Interest income

            

      Other income (expense)

            

      Other income (expense)

            

      Equity in net income of unconsolidated affiliate

       979 1,566 3,051 3,109 8,705 

      Equity in net income of unconsolidated affiliate

       2,761 1,799 1,633 2,722 8,915 
                             

      Net income (1)

      Net income (1)

       $8,376 $13,213 $15,747 $16,713 $54,049 

      Net income (1)

       $14,386 $13,693 $14,794 $15,590 $58,463 
                             

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       Forecasted 


       Forecasted 
       Three Months Ending  
       


       Three Months Ending  
       
       Twelve Months
      Ending
      September 30,
      2011
       


       September 30,
      2010
       December 31,
      2010
       March 31,
      2011
       June 30,
      2011,
       Twelve Months
      Ending June 30,
      2011
       
       December 31,
      2010
       March 31,
      2011
       June 30,
      2011,
       September 30,
      2011
       


       (in thousands, except distributions per unit)
       
       (in thousands, except distributions per unit)
       

      Net income (1)

      Net income (1)

       $8,376 $13,213 $15,747 $16,713 $54,049 

      Net income (1)

       $14,386 $13,693 $14,794 $15,590 $58,463 
                             

      Plus:

      Plus:

       

      Plus:

       

      Depreciation, depletion and amortization

       9,006 8,898 9,264 9,177 36,345 

      Depreciation, depletion and amortization

       8,932 9,300 9,130 9,259 36,620 

      Interest expense

       909 798 951 1,145 3,803 

      Interest expense

       776 867 982 1,039 3,664 
                             

      EBITDA (1)

      EBITDA (1)

       $18,291 $22,909 $25,962 $27,035 $94,197 

      EBITDA (1)

       $24,093 $23,860 $24,906 $25,888 $98,747 
                             

      Less:

      Less:

       

      Less:

       

      Cash interest expense

       (793) (581) (634) (673) (2,681)

      Cash interest expense

       (565) (571) (561) (558) (2,254)

      Maintenance capital expenditures

       (3,540) (3,755) (4,675) (4,716) (16,686)

      Maintenance capital expenditures

       (4,067) (4,751) (4,904) (4,893) (18,614)

      Expansion capital expenditures

       (9,554) (5,914) (10,789) (19,836) (46,092)

      Expansion capital expenditures

       (4,950) (9,735) (11,883) (3,042) (29,611)

      Plus:

      Plus:

       

      Plus:

       

      Borrowings or cash on hand for expansion capital expenditures

       9,554 5,914 10,789 19,836 46,092 

      Borrowings or cash on hand for expansion capital expenditures

       4,950 9,735 11,883 3,042 29,611 
                             

      Cash available for distribution (1)

      Cash available for distribution (1)

       $13,958 $18,573 $20,653 $21,646 $74,831 

      Cash available for distribution (1)

       $19,462 $18,539 $19,441 $20,437 $77,879 
                             

      Implied cash distributions based on the minimum quarterly distribution per unit:

      Implied cash distributions based on the minimum quarterly distribution per unit:

       

      Implied cash distributions based on the minimum quarterly distribution per unit:

       

      Annualized minimum quarterly distribution per unit

       $0.445 $0.445 $0.445 $0.445 $1.78 

      Annualized minimum quarterly distribution per unit

       $0.445 $0.445 $0.445 $0.445 $1.780 

      Distribution to common unitholders

       $5,517 $5,517 $5,517 $5,517 $22,067 

      Distribution to common unitholders

       $5,517 $5,517 $5,517 $5,517 $22,067 

      Distribution to subordinated unitholder

       5,517 5,517 5,517 5,517 22,067 

      Distribution to subordinated unitholder

       5,517 5,517 5,517 5,517 22,067 

      Distribution to general partner

       225 225 225 225 901 

      Distribution to general partner

       225 225 225 225 901 
                             
       

      Total distributions (1)

       $11,259 $11,259 $11,259 $11,259 $45,034  

      Total distributions (1)

       $11,259 $11,259 $11,259 $11,259 $45,034 
                             

      Excess (shortfall) (1)

      Excess (shortfall) (1)

       $2,700 $7,315 $9,395 $10,388 $29,797 

      Excess (shortfall) (1)

       $8,204 $7,280 $8,183 $9,179 $32,845 
                             

      (1)
      Based on actual amounts and not the rounded amounts shown in this table.

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      PROVISIONS OF OUR PARTNERSHIP AGREEMENT RELATING TO CASH DISTRIBUTIONS

              Set forth below is a summary of the significant provisions of our partnership agreement that relate to cash distributions.

      Distributions of Available Cash

      General

              Our partnership agreement requires that, within 45 days after the end of each quarter, beginning with the quarter ending September 30, 2010, we distribute all of our available cash to unitholders of record on the applicable record date. We will adjust the minimum quarterly distribution for the period from the closing of the offering through September 30, 2010.

      Definition of Available Cash

              Available cash, for any quarter, consists of all cash and cash equivalents on hand at the end of that quarter:

        less, the amount of cash reserves established by our general partner to:

        provide for the proper conduct of our business;

        comply with applicable law, any of our debt instruments or other agreements; or

        provide funds for distributions to our unitholders for any one or more of the next four quarters (provided that our general partner may not establish cash reserves for future distributions unless it determines that the establishment of reserves will not prevent us from distributing the minimum quarterly distribution on all common units and any cumulative arrearages for such quarter);

        plus, if our general partner so determines, all or a portion of cash on hand on the date of determination of available cash for the quarter resulting from working capital borrowings made after the end of the quarter.

              The purpose and effect of the last bullet point above is to allow our general partner, if it so decides, to use cash from working capital borrowings made after the end of the quarter but on or before the date of determination of available cash for that quarter to pay distributions to unitholders. Under our partnership agreement, working capital borrowings are borrowings that are made under a credit agreement, commercial paper facility or similar financing arrangement, and in all cases are used solely for working capital purposes or to pay distributions to partners and with the intent of the borrower to repay such borrowings within twelve months from sources other than additional working capital borrowings. We may borrow funds to pay quarterly distributions to our unitholders.

      Distributions of the Minimum Quarterly Distribution

              We will distribute to the holders of common and subordinated units on a quarterly basis the minimum quarterly distribution of $0.445 per unit, or $1.78 on an annualized basis, to the extent we have sufficient cash from our operations after establishment of cash reserves and payment of fees and expenses, including payments to our general partner and its affiliates. However, there is no guarantee that we will pay the minimum quarterly distribution on the units in any quarter.


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      Even if our cash distribution policy is not modified or revoked, the amount of distributions paid


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      under our policy and the decision to make any distribution is determined by our general partner, taking into consideration the terms of our partnership agreement.

      General Partner Interest and Incentive Distribution Rights

              Initially, our general partner will be entitled to 2.0% of all distributions that we make prior to our liquidation. Our general partner has the right, but not the obligation, to contribute a proportionate amount of capital to us to maintain its current general partner interest. Our general partner's initial 2.0% interest in our distributions may be reduced if we issue additional limited partner units in the future and our general partner does not contribute a proportionate amount of capital to us to maintain its 2.0% general partner interest.

              Our general partner also currently holds incentive distribution rights that entitle it to receive increasing percentages, up to a maximum of 50.0%, of the cash we distribute from operating surplus (as defined below) in excess of $0.445 per unit per quarter. We view these distributions as an incentive fee, providing our general partner with a direct financial incentive to expand the profitability of our business to enable us to increase distributions to our limited partners. The maximum distribution of 50.0% includes distributions paid to our general partner on its 2.0% general partner interest and assumes that our general partner maintains its general partner interest at 2.0%. The maximum distribution of 50.0% does not include any distributions that our general partner may receive on any limited partner units that it owns.

      Operating Surplus and Capital Surplus

      General

              All cash distributed will be characterized as either "operating surplus" or "capital surplus." Our partnership agreement requires that we distribute available cash from operating surplus differently than available cash from capital surplus.

      Operating Surplus

              Operating surplus consists of:

        $25.0 million (as described below);plus

        all of our cash receipts after the closing of this offering, excluding cash from interim capital transactions, which include the following:

        borrowings that are not working capital borrowings;

        sales of equity and debt securities;

        sales or other dispositions of assets outside the ordinary course of business; and

        capital contributions received.

          provided that cash receipts from the termination of a commodity hedge or interest rate hedge prior to its specified termination date shall be included in operating surplus in


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          equal quarterly installments over the remaining scheduled life of such commodity hedge or interest rate hedge;plus

        working capital borrowings made after the end of a period but on or before the date of determination of operating surplus for the period;plus


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        cash distributions paid on equity issued (including incremental distributions on incentive distribution rights) to finance all or a portion of expansion capital expenditures in respect of the period from such financing until the earlier to occur of the date the capital asset commences commercial service and the date that it is abandoned or disposed of;plus

        cash distributions paid on equity issued by us (including incremental distributions on incentive distribution rights) to pay the construction period interest on debt incurred, or to pay construction period distributions on equity issued, to finance the expansion capital expenditures referred to above;less

        all of our operating expenditures (as defined below) after the closing of this offering;less

        the amount of cash reserves established by our general partner to provide funds for future operating expenditures;less

        all working capital borrowings not repaid within twelve months after having been incurred or repaid within such twelve-month period with the proceeds of additional working capital borrowings;less

        any loss realized on disposition of an investment capital expenditure.

              As described above, operating surplus does not reflect actual cash on hand that is available for distribution to our unitholders and is not limited to cash generated by our operations. For example, it includes $25.0 million that will enable us, if we choose, to distribute as operating surplus cash we receive in the future from non-operating sources such as asset sales, issuances of securities and long-term borrowings that would otherwise be distributed as capital surplus. In addition, the effect of including, as described above, certain cash distributions on equity interests in operating surplus will be to increase operating surplus by the amount of any such cash distributions. As a result, we may also distribute as operating surplus up to the amount of any such cash that we receive from non-operating sources.

              The proceeds of working capital borrowings increase operating surplus and repayments of working capital borrowings are generally operating expenditures, as described below, and thus reduce operating surplus when made. However, if a working capital borrowing is not repaid during the twelve-month period following the borrowing, it will be deemed repaid at the end of such period, thus decreasing operating surplus at such time. When such working capital borrowing is in fact repaid, it will be excluded from operating expenditures because operating surplus will have been previously reduced by the deemed repayment.

              We define operating expenditures in the partnership agreement, and it generally means all of our cash expenditures, including, but not limited to, taxes, reimbursement of expenses to our general partner or its affiliates, payments made under interest rate hedge agreements or commodity hedge agreements (provided that (1) with respect to amounts paid in connection with the initial purchase of an interest rate hedge contract or a commodity hedge contract, such amounts will be amortized over the life of the applicable interest rate hedge contract or


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      commodity hedge contract and (2) payments made in connection with the termination of any interest rate hedge contract or commodity hedge contract prior to the expiration of its stipulated settlement or termination date will be included in operating expenditures in equal quarterly installments over the remaining scheduled life of such interest rate hedge contract or commodity hedge contract), officer compensation, repayment of working capital borrowings, debt service


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      payments and estimated maintenance capital expenditures (as discussed in further detail below), provided that operating expenditures will not include:

        repayment of working capital borrowings deducted from operating surplus pursuant to the penultimate bullet point of the definition of operating surplus above when such repayment actually occurs;

        payments (including prepayments and prepayment penalties) of principal of and premium on indebtedness, other than working capital borrowings;

        expansion capital expenditures;

        actual maintenance capital expenditures (as discussed in further detail below);

        investment capital expenditures;

        payment of transaction expenses relating to interim capital transactions;

        distributions to our partners (including distributions in respect of our incentive distribution rights); or

        repurchases of equity interests except to fund obligations under employee benefit plans.

      Capital Surplus

              Capital surplus is defined in our partnership agreement as any distribution of available cash in excess of our operating surplus. Accordingly, capital surplus would generally be generated by:

        borrowings other than working capital borrowings;

        sales of our equity and debt securities; and

        sales or other dispositions of assets for cash, other than inventory, accounts receivable and other assets sold in the ordinary course of business or as part of normal retirement or replacement of assets.

              All available cash distributed by us on any date from any source will be treated as distributed from operating surplus until the sum of all available cash distributed since the closing of the initial public offering equals the operating surplus from the closing of the initial public offering through the end of the quarter immediately preceding that distribution. Any excess available cash distributed by us on that date will be deemed to be capital surplus.

      Characterization of Cash Distributions

              Our partnership agreement requires that we treat all available cash distributed as coming from operating surplus until the sum of all available cash distributed since the closing of this offering equals the operating surplus from the closing of this offering through the end of the


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      quarter immediately preceding that distribution. Our partnership agreement requires that we treat any amount distributed in excess of operating surplus, regardless of its source, as capital surplus. We do not anticipate that we will make any distributions from capital surplus.


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      Capital Expenditures

              Estimated maintenance capital expenditures reduce operating surplus, but expansion capital expenditures, actual maintenance capital expenditures and investment capital expenditures do not. Maintenance capital expenditures are those capital expenditures required to maintain our long-term operating capacity. Examples of maintenance capital expenditures include expenditures associated with the replacement of equipment and coal reserves, whether through the expansion of an existing mine or the acquisition or development of new reserves, to the extent such expenditures are made to maintain our long-term operating capacity. Maintenance capital expenditures will also include interest (and related fees) on debt incurred and distributions on equity issued (including incremental distributions on incentive distribution rights) to finance all or any portion of the construction or development of a replacement asset that is paid in respect of the period that begins when we enter into a binding obligation to commence constructing or developing a replacement asset and ending on the earlier to occur of the date that any such replacement asset commences commercial service and the date that it is abandoned or disposed of. Capital expenditures made solely for investment purposes will not be considered maintenance capital expenditures.

              Because our maintenance capital expenditures can be irregular, the amount of our actual maintenance capital expenditures may differ substantially from period to period, which could cause similar fluctuations in the amounts of operating surplus, adjusted operating surplus and cash available for distribution to our unitholders if we subtracted actual maintenance capital expenditures from operating surplus.

              Our partnership agreement will require that an estimate of the average quarterly maintenance capital expenditures necessary to maintain our operating capacity over the long-term be subtracted from operating surplus each quarter as opposed to the actual amounts spent. The amount of estimated maintenance capital expenditures deducted from operating surplus for those periods will be subject to review and change by our general partner at least once a year, provided that any change is approved by our conflicts committee. The estimate will be made at least annually and whenever an event occurs that is likely to result in a material adjustment to the amount of our maintenance capital expenditures, such as a major acquisition or the introduction of new governmental regulations that will impact our business. Our partnership agreement does not cap the amount of maintenance capital expenditures that our general partner may estimate. For purposes of calculating operating surplus, any adjustment to this estimate will be prospective only. For a discussion of the amounts we have allocated toward estimated maintenance capital expenditures, please read "Cash Distribution Policy and Restrictions on Distributions."

              The use of estimated maintenance capital expenditures in calculating operating surplus will have the following effects:

        it will reduce the risk that maintenance capital expenditures in any one quarter will be large enough to render operating surplus less than the initial quarterly distribution to be paid on all the units for the quarter and subsequent quarters;

        it will increase our ability to distribute as operating surplus cash we receive from non-operating sources; and

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        it will be more difficult for us to raise our distribution above the minimum quarterly distribution and pay incentive distributions on the incentive distribution rights held by our general partner.

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              Expansion capital expenditures are those capital expenditures that we expect will increase our operating capacity over the long term. Examples of expansion capital expenditures include the acquisition of reserves, equipment or a new mine or the expansion of an existing mine, to the extent such capital expenditures are expected to expand our long-term operating capacity. Expansion capital expenditures will also include interest (and related fees) on debt incurred and distributions on equity issued (including incremental distributions on incentive distribution rights) to finance all or any portion of the construction of such capital improvement in respect of the period that commences when we enter into a binding obligation to commence construction of a capital improvement and ending on the earlier to occur of date any such capital improvement commences commercial service and the date that it is disposed of or abandoned. Capital expenditures made solely for investment purposes will not be considered expansion capital expenditures.

              Investment capital expenditures are those capital expenditures that are neither maintenance capital expenditures nor expansion capital expenditures. Investment capital expenditures largely will consist of capital expenditures made for investment purposes. Examples of investment capital expenditures include traditional capital expenditures for investment purposes, such as purchases of securities, as well as other capital expenditures that might be made in lieu of such traditional investment capital expenditures, such as the acquisition of a capital asset for investment purposes or development of assets that are in excess of the maintenance of our existing operating capacity, but which are not expected to expand, for more than the short term, our operating capacity.

              As described below, neither investment capital expenditures nor expansion capital expenditures are included in operating expenditures, and thus will not reduce operating surplus. Because expansion capital expenditures include interest payments (and related fees) on debt incurred to finance all or a portion of the construction, replacement or improvement of a capital asset during the period that begins when we enter into a binding obligation to commence construction of a capital improvement and ending on the earlier to occur of the date any such capital asset commences commercial service and the date that it is abandoned or disposed of, such interest payments also do not reduce operating surplus. Losses on disposition of an investment capital expenditure will reduce operating surplus when realized and cash receipts from an investment capital expenditure will be treated as a cash receipt for purposes of calculating operating surplus only to the extent the cash receipt is a return on principal.

              Capital expenditures that are made in part for maintenance capital purposes, investment capital purposes and/or expansion capital purposes will be allocated as maintenance capital expenditures, investment capital expenditures or expansion capital expenditure by our general partner.

      Subordination Period

      General

              Our partnership agreement provides that, during the subordination period (which we define below), the common units will have the right to receive distributions of available cash from operating surplus each quarter in an amount equal to $0.445 per common unit, which amount is defined in our partnership agreement as the minimum quarterly distribution, plus any arrearages


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      in the payment of the minimum quarterly distribution on the common units from prior quarters, before any distributions of available cash from operating surplus may be made on the subordinated units. These units are deemed "subordinated" because for a period of time, referred to as the subordination period, the subordinated units will not be entitled to receive any


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      distributions from operating surplus until the common units have received the minimum quarterly distribution plus any arrearages in the payment of the minimum quarterly distribution from prior quarters. Furthermore, no arrearages will be paid on the subordinated units. The practical effect of the subordinated units is to increase the likelihood that during the subordination period there will be sufficient available cash from operating surplus to pay the minimum quarterly distribution on the common units.

      Subordination Period

              Except as described below, the subordination period will begin on the closing date of this offering and expire on the first business day after the distribution to unitholders in respect of any quarter, beginning with the quarter ending JuneSeptember 30, 2013, if each of the following has occurred:

        distributions of available cash from operating surplus on each of the outstanding common and subordinated units and the general partner interest equaled or exceeded the minimum quarterly distribution for each of the three consecutive, non-overlapping four-quarter periods immediately preceding that date;

        the "adjusted operating surplus" (as defined below) generated during each of the three consecutive, non-overlapping four-quarter periods immediately preceding that date equaled or exceeded the sum of the minimum quarterly distribution on all of the outstanding common and subordinated units and the general partner interest during those periods on a fully diluted weighted average basis; and

        there are no arrearages in payment of the minimum quarterly distribution on the common units.

      Early Termination of Subordination Period

              Notwithstanding the foregoing, the subordination period will automatically terminate on the first business day after the distribution to unitholders in respect of any quarter, if each of the following has occurred:

        distributions of available cash from operating surplus on each of the outstanding common and subordinated units and the general partner interest equaled or exceeded $2.67 (150.0% of the annualized minimum quarterly distribution) for the four-quarter period immediately preceding that date;

        the "adjusted operating surplus" (as defined below) generated during the four-quarter period immediately preceding that date equaled or exceeded the sum of $2.67 (150.0% of the annualized minimum quarterly distribution) on all of the outstanding common and subordinated units and the general partner interest on a fully diluted weighted average basis and the related distribution on the incentive distribution rights; and

        there are no arrearages in payment of the minimum quarterly distributions on the common units.

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              We do not expect to satisfy the foregoing requirements for any four-quarter period ending on or before September 30, 2011.

      Expiration Upon Removal of the General Partner

              In addition, if the unitholders remove our general partner other than for cause:

        the subordinated units held by any person will immediately and automatically convert into common units on a one-for-one basis, provided (1) neither such person nor any of its affiliates voted any of its units in favor of the removal and (2) such person is not an affiliate of the successor general partner; and

        if all of the subordinated units convert pursuant to the foregoing, all cumulative common unit arrearages on the common units will be extinguished and the subordination period will end.

      Expiration of the Subordination Period

              When the subordination period ends, each outstanding subordinated unit will convert into one common unit and will then participate pro-rata with the other common units in distributions of available cash.

      Adjusted Operating Surplus

              Adjusted operating surplus is intended to reflect the cash generated from operations during a particular period and therefore excludes net increases in working capital borrowings and net drawdowns of reserves of cash generated in prior periods. Adjusted operating surplus consists of:

        operating surplus generated with respect to that period (excluding any amounts attributable to the items described in the first bullet point under "—Operating Surplus and Capital Surplus—Operating Surplus" above);less

        any net increase in working capital borrowings with respect to that period;less

        any net decrease in cash reserves for operating expenditures with respect to that period not relating to an operating expenditure made with respect to that period;plus

        any net decrease in working capital borrowings with respect to that period;plus

        any net increase in cash reserves for operating expenditures with respect to that period required by any debt instrument for the repayment of principal, interest or premium;plus

        any net decrease made in subsequent periods in cash reserves for operating expenditures initially established with respect to such period to the extent such decrease results in a reduction of adjusted operating surplus in subsequent periods pursuant to the third bullet point above.

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      Distributions of Available Cash From Operating Surplus During the Subordination Period

              Our partnership agreement requires that we make distributions of available cash from operating surplus for any quarter during the subordination period in the following manner:

        first, 98.0% to the common unitholders, pro rata, and 2.0% to our general partner, until we distribute for each common unit an amount equal to the minimum quarterly distribution for that quarter;

        second, 98.0% to the common unitholders, pro rata, and 2.0% to our general partner, until we distribute for each common unit an amount equal to any arrearages in payment of the minimum quarterly distribution on the common units for any prior quarters during the subordination period;

        third, 98.0% to the subordinated unitholders, pro rata, and 2.0% to our general partner, until we distribute for each subordinated unit an amount equal to the minimum quarterly distribution for that quarter; and

        thereafter, in the manner described in "—General Partner Interest and Incentive Distribution Rights" below.

              The preceding discussion is based on the assumptions that our general partner maintains its 2.0% general partner interest and that we do not issue additional classes of equity interests.

      Distributions of Available Cash From Operating Surplus After the Subordination Period

              Our partnership agreement requires that we make distributions of available cash from operating surplus for any quarter after the subordination period in the following manner:

        first, 98.0% to all unitholders, pro rata, and 2.0% to our general partner, until we distribute for each unit an amount equal to the minimum quarterly distribution for that quarter; and

        thereafter, in the manner described in "—General Partner Interest and Incentive Distribution Rights" below.

              The preceding discussion is based on the assumptions that our general partner maintains its 2.0% general partner interest and that we do not issue additional classes of equity interests.

      General Partner Interest and Incentive Distribution Rights

              Our partnership agreement provides that our general partner initially will be entitled to 2.0% of all distributions that we make prior to our liquidation. Our general partner has the right, but not the obligation, to contribute a proportionate amount of capital to us to maintain its 2.0% general partner interest if we issue additional units. Our general partner's 2.0% interest, and the percentage of our cash distributions to which it is entitled, will be proportionately reduced if we issue additional units in the future (other than the issuance of common units upon exercise by the underwriters of their option to purchase additional common units or the issuance of common units upon conversion of outstanding subordinated units) and our general partner does not contribute a proportionate amount of capital to us in order to maintain its 2.0% general partner interest. Our partnership agreement does not require that the general partner fund its capital contribution with cash and our general partner may fund its capital contribution by the contribution to us of common units or other property.


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              Incentive distribution rights represent the right to receive an increasing percentage (13.0%, 23.0% and 48.0%, in each case, not including distributions paid to the general partner on its 2.0% general partner interest) of quarterly distributions of available cash from operating surplus after the minimum quarterly distribution and the target distribution levels have been achieved. Our general partner currently holds the incentive distribution rights, but may transfer these rights separately from its general partner interest, subject to restrictions in the partnership agreement. We view distributions on the incentive distribution rights as an incentive fee, providing our general partner with a direct financial incentive to expand the profitability of our business to enable us to increase distributions to our limited partners.

              The following discussion assumes that our general partner maintains its 2.0% general partner interest, that there are no arrearages on common units and that our general partner continues to own the incentive distribution rights.

              If for any quarter:

        we have distributed available cash from operating surplus to the common and subordinated unitholders in an amount equal to the minimum quarterly distribution; and

        we have distributed available cash from operating surplus on outstanding common units in an amount necessary to eliminate any cumulative arrearages in payment of the minimum quarterly distribution;

      then, our partnership agreement requires that we distribute any additional available cash from operating surplus for that quarter among the unitholders and the general partner in the following manner:

        first, 98.0% to all unitholders, pro rata, and 2.0% to our general partner, until each unitholder receives a total of $0.51175 per unit for that quarter (the "first target distribution");

        second, 85.0% to all unitholders, pro rata, and 15.0% to our general partner, until each unitholder receives a total of $0.55625 per unit for that quarter (the "second target distribution");

        third, 75.0% to all unitholders, pro rata, and 25.0% to our general partner, until each unitholder receives a total of $0.6675 per unit for that quarter (the "third target distribution"); and

        thereafter, 50.0% to all unitholders, pro rata, and 50.0% to our general partner.

      Percentage Allocations of Available Cash From Operating Surplus

              The following table illustrates the percentage allocations of available cash from operating surplus between the unitholders and our general partner based on the specified target distribution levels. The amounts set forth under "Marginal Percentage Interest in Distributions" are the percentage interests of our general partner and the unitholders in any available cash from operating surplus we distribute up to and including the corresponding amount in the column "Total Quarterly Distribution Per Unit." The percentage interests shown for our unitholders and our general partner for the minimum quarterly distribution are also applicable to quarterly distribution amounts that are less than the minimum quarterly distribution. The percentage interests set forth below for our general partner include distributions paid on its 2.0% general partner interest, assume our general partner has contributed any additional capital to maintain


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      its 2.0% general partner interest and has not transferred its incentive distribution rights and there are no arrearages on common units.

       
        
       Marginal Percentage
      Interest in Distributions
        
       
       
       Total Quarterly
      Distribution Per Unit
       Unitholders General
      Partner
        
       

      Minimum Quarterly Distribution

       $0.445 98.0%  2.0%   

      First Target Distribution

       up to $0.51175 98.0%  2.0%   

      Second Target Distribution

       above $0.51175 up to $0.55625 85.0%  15.0%   

      Third Target Distribution

       above $0.55625 up to $0.6675 75.0%  25.0%   

      Thereafter

       above $0.6675 50.0%  50.0%   

      General Partner's Right to Reset Incentive Distribution Levels

              Our general partner, as the initial holder of our incentive distribution rights, has the right under our partnership agreement to elect to relinquish the right to receive incentive distribution payments based on the initial cash target distribution levels and to reset, at higher levels, the minimum quarterly distribution amount and cash target distribution levels upon which the incentive distribution payments to our general partner would be set. If our general partner transfers all or a portion of our incentive distribution rights in the future, then the holder or holders of a majority of our incentive distribution rights will be entitled to exercise this right. The following discussion assumes that our general partner holds all of the incentive distribution rights at the time that a reset election is made. The right to reset the minimum quarterly distribution amount and the target distribution levels upon which the incentive distributions are based may be exercised, without approval of our unitholders or the conflicts committee of our general partner, at any time when there are no subordinated units outstanding and we have made cash distributions to the holders of the incentive distribution rights at the highest level of incentive distribution for each of the prior four consecutive fiscal quarters. The reset minimum quarterly distribution amount and target distribution levels will be higher than the minimum quarterly distribution amount and the target distribution levels prior to the reset such that there will be no incentive distributions paid under the reset target distribution levels until cash distributions per unit following this event increase as described below. We anticipate that our general partner would exercise this reset right in order to facilitate acquisitions or internal growth projects that would otherwise not be sufficiently accretive to cash distributions per common unit, taking into account the existing levels of incentive distribution payments being made to our general partner.

              In connection with the resetting of the minimum quarterly distribution amount and the target distribution levels and the corresponding relinquishment by our general partner of incentive distribution payments based on the target cash distributions prior to the reset, our general partner will be entitled to receive a number of newly issued common units based on a predetermined formula described below that takes into account the "cash parity" value of the average cash distributions related to the incentive distribution rights received by our general partner for the two quarters prior to the reset event as compared to the average cash distributions per common unit during this period. In addition, our general partner will be issued a general partner interest necessary to maintain its general partner interest in us immediately prior to the reset election.

              The number of common units that our general partner would be entitled to receive from us in connection with a resetting of the minimum quarterly distribution amount and the target distribution levels then in effect would be equal to the quotient determined by dividing (x) the


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      average amount of cash distributions received by our general partner in respect of its incentive distribution rights during the two consecutive fiscal quarters ended immediately prior to the date of such reset election by (y) the average of the amount of cash distributed per common unit during each of these two quarters.

              Following a reset election, the minimum quarterly distribution amount will be reset to an amount equal to the average cash distribution amount per unit for the two fiscal quarters immediately preceding the reset election (which amount we refer to as the "reset minimum quarterly distribution") and the target distribution levels will be reset to be correspondingly higher such that we would distribute all of our available cash from operating surplus for each quarter thereafter as follows:

        first, 98.0% to all unitholders, pro rata, and 2.0% to our general partner, until each unitholder receives an amount per unit equal to 115.0% of the reset minimum quarterly distribution for that quarter;

        second, 85.0% to all unitholders, pro rata, and 15.0% to our general partner, until each unitholder receives an amount per unit equal to 125.0% of the reset minimum quarterly distribution for the quarter;

        third, 75.0% to all unitholders, pro rata, and 25.0% to our general partner, until each unitholder receives an amount per unit equal to 150.0% of the reset minimum quarterly distribution for the quarter; and

        thereafter, 50.0% to all unitholders, pro rata, and 50.0% to our general partner.

              The following table illustrates the percentage allocation of available cash from operating surplus between the unitholders and our general partner at various cash distribution levels (1) pursuant to the cash distribution provisions of our partnership agreement in effect at the closing of this offering, as well as (2) following a hypothetical reset of the minimum quarterly distribution and target distribution levels based on the assumption that the average quarterly cash distribution amount per common unit during the two fiscal quarters immediately preceding the reset election was $0.712.

       
        
        
       Marginal Percentage
      Interest in
      Distribution
        
        
       
       Quarterly Distribution
      Per Unit
      Prior to Reset
       Unitholders General
      Partner
       Quarterly Distribution
      Per Unit
      Following Hypothetical Reset

      Minimum Quarterly Distribution

        $0.445  98.0% 2.0%$0.712

      First Target Distribution

        up to $0.51175  98.0% 2.0%up to $0.8188(1)

      Second Target Distribution

        above $0.51175 up to $0.55625  85.0% 15.0%above $0.8188(1) up to $0.89(2)

      Third Target Distribution

        above $0.55625 up to $0.6675  75.0% 25.0%above $0.89(2) up to $1.068(3)

      Thereafter

        above $0.6675  50.0% 50.0%above $1.068(3)

      (1)
      This amount is 115.0% of the hypothetical reset minimum quarterly distribution.
      (2)
      This amount is 125.0% of the hypothetical reset minimum quarterly distribution.
      (3)
      This amount is 150.0% of the hypothetical reset minimum quarterly distribution.

              The following table illustrates the total amount of available cash from operating surplus that would be distributed to the unitholders and our general partner, including in respect of


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      incentive distribution rights, based on an average of the amounts distributed for a quarter for the


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      two quarters immediately prior to the reset. The table assumes that immediately prior to the reset there would be 24,794,000 common units outstanding, our general partner has maintained its 2.0% general partner interest, and the average distribution to each common unit would be $0.712 per quarter for the two quarters prior to the reset.

       
        
        
       Cash Distributions to General Partner
      Prior to Reset
        
       
       
        
       Cash
      Distributions
      to Common
      Unitholders
      Prior to Reset
        
       
       
       Quarterly
      Distributions
      Per Unit
      Prior to Reset
        
       
       
       Common
      Units
       2.0% General
      Partner
      Interest
       Incentive
      Distribution
      Rights
       Total Total
      Distributions
       

      Minimum Quarterly Distribution

       $0.445 $11,033,330 $ $225,170 $ $225,170 $11,258,500 

      First Target Distribution

       

      up to $0.51175

        
      1,655,000
        
        
      33,776
        
        
      33,776
        
      1,688,775
       

      Second Target Distribution

       

      above $.51175

                         

       up to $0.55625  1,103,333    25,961  168,745  194,706  1,298,039 

      Third Target Distribution

       

      above $0.55625

                         

       up to $0.6675  2,758,333    73,556  845,889  919,444  3,677,777 

      Thereafter

       

      above $0.6675

        
      1,103,333
        
        
      44,133
        
      1,059,200
        
      1,103,333
        
      2,206,666
       
                      

         $17,653,328 $ $402,595 $2,073,833 $2,476,428 $20,129,756 
                      

              The following table illustrates the total amount of available cash from operating surplus that would be distributed to the unitholders and our general partner, including in respect of incentive distribution rights, with respect to the quarter in which the reset occurs. The table reflects that as a result of the reset there would be 27,706,687 common units outstanding, our general partner's 2.0% interest has been maintained, and the average distribution to each common unit would be $0.712. The number of common units to be issued to our general partner upon the reset was calculated by dividing (1) the average of the amounts received by our general partner in respect of its incentive distribution rights for the two quarters prior to the reset as shown in the table above, or $2,073,833, by (2) the average available cash distributed on each common unit for the two quarters prior to the reset as shown in the table above, or $0.712.

       
        
        
       Cash Distributions to General Partner
      After Reset
        
       
       
        
       Cash
      Distributions
      to Common
      Unitholders
      After Reset
        
       
       
       Quarterly
      Distributions
      Per Unit
      After Reset
        
       
       
       Common
      Units
       2.0% General
      Partner
      Interest
       Incentive
      Distribution
      Rights
       Total Total
      Distributions
       

      Minimum Quarterly Distribution

        $0.712 $17,653,328 $2,073,833 $402,595 $ $2,476,428 $20,129,756 

      First Target Distribution

        up to $0.8188             

      Second Target Distribution

        above $0.8188                   

        up to $0.89             

      Third Target Distribution

        above $0.89                   

        up to $1.068             

      Thereafter

        above $1.068             
                       

          $17,653,328 $2,073,833 $402,595 $ $2,476,428 $20,129,756 
                       

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              Our general partner will be entitled to cause the minimum quarterly distribution amount and the target distribution levels to be reset on more than one occasion, provided that it may not make a reset election except at a time when it has received incentive distributions for the prior four consecutive fiscal quarters based on the highest level of incentive distributions that it is entitled to receive under our partnership agreement.

      Distributions From Capital Surplus

      How Distributions From Capital Surplus Will Be Made

              Our partnership agreement requires that we make distributions of available cash from capital surplus, if any, in the following manner:

        first, 98.0% to all unitholders, pro rata, and 2.0% to our general partner, until we distribute for each common unit that was issued in this offering, an amount of available cash from capital surplus equal to the initial public offering price;

        second, 98.0% to the common unitholders, pro rata, and 2.0% to our general partner, until we distribute for each common unit an amount of available cash from capital surplus equal to any unpaid arrearages in payment of the minimum quarterly distribution on the common units; and

        thereafter, we will make all distributions of available cash from capital surplus as if they were from operating surplus.

              The preceding paragraph assumes that our general partner maintains its 2.0% general partner interest and that we do not issue additional classes of equity interests.

      Effect of a Distribution From Capital Surplus

              Our partnership agreement treats a distribution of capital surplus as the repayment of the initial unit price from this initial public offering, which is a return of capital. The initial public offering price less any distributions of capital surplus per unit is referred to as the "unrecovered initial unit price." Each time a distribution of capital surplus is made, the minimum quarterly distribution and the target distribution levels will be reduced in the same proportion as the corresponding reduction in the unrecovered initial unit price. Because distributions of capital surplus will reduce the minimum quarterly distribution and target distribution levels after any of these distributions are made, it may be easier for our general partner to receive incentive distributions and for the subordinated units to convert into common units. However, any distribution of capital surplus before the unrecovered initial unit price is reduced to zero cannot be applied to the payment of the minimum quarterly distribution or any arrearages.

              Once we distribute capital surplus on a unit issued in this offering in an amount equal to the initial unit price, our partnership agreement specifies that the minimum quarterly distribution and the target distribution levels will be reduced to zero. Our partnership agreement specifies that we then make all future distributions from operating surplus, with 50.0% being paid to the holders of units and 50.0% to our general partner. The percentage interests shown for our general partner include its 2.0% general partner interest and assume our general partner has not transferred the incentive distribution rights.


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      Adjustment to the Minimum Quarterly Distribution and Target Distribution Levels

              In addition to adjusting the minimum quarterly distribution and target distribution levels to reflect a distribution of capital surplus, if we combine our units into fewer units or subdivide our units into a greater number of units, our partnership agreement specifies that the following items will be proportionately adjusted:

        the minimum quarterly distribution;

        the target distribution levels;

        the unrecovered initial unit price; and

        the per unit amount of any outstanding arrearages in payment of the minimum quarterly distribution on the common units.

              For example, if a two-for-one split of the common units should occur, the minimum quarterly distribution, the target distribution levels and the unrecovered initial unit price would each be reduced to 50.0% of its initial level. If we combine our common units into a lesser number of units or subdivide our common units into a greater number of units, we will combine or subdivide our subordinated units using the same ratio applied to the common units. Our partnership agreement provides that we do not make any adjustment by reason of the issuance of additional units for cash or property.

              In addition, if legislation is enacted or if existing law is modified or interpreted by a governmental taxing authority, so that we become taxable as a corporation or otherwise subject to taxation as an entity for federal, state or local income tax purposes, our partnership agreement specifies that the minimum quarterly distribution and the target distribution levels for each quarter may, in the sole discretion of the general partner, be reduced by multiplying each distribution level by a fraction, the numerator of which is available cash for that quarter and the denominator of which is the sum of available cash for that quarter plus our general partner's estimate of our aggregate liability for the quarter for such income taxes payable by reason of such legislation or interpretation. To the extent that the actual tax liability differs from the estimated tax liability for any quarter, the difference will be accounted for in subsequent quarters.

      Distributions of Cash Upon Liquidation

      General

              If we dissolve in accordance with the partnership agreement, we will sell or otherwise dispose of our assets in a process called liquidation. We will first apply the proceeds of liquidation to the payment of our creditors. We will distribute any remaining proceeds to the unitholders, the general partner and the holders of the incentive distribution rights, in accordance with their capital account balances, as adjusted to reflect any gain or loss upon the sale or other disposition of our assets in liquidation.

              The allocations of gain and loss upon liquidation are intended, to the extent possible, to entitle the holders of common units to a preference over the holders of subordinated units upon our liquidation, to the extent required to permit common unitholders to receive their unrecovered initial unit price plus the minimum quarterly distribution for the quarter during which liquidation occurs plus any unpaid arrearages in payment of the minimum quarterly distribution on the common units. However, there may not be sufficient gain upon our


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      liquidation to enable the common unitholders to fully recover all of these amounts, even though


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      there may be cash available for distribution to the holders of subordinated units. Any further net gain recognized upon liquidation will be allocated in a manner that takes into account the incentive distribution rights of our general partner.

      Manner of Adjustments for Gain

              The manner of the adjustment for gain is set forth in the partnership agreement. If our liquidation occurs before the end of the subordination period, we will allocate any gain to the partners in the following manner:

        first, to our general partner to the extent of certain prior losses specially allocated to the general partner;

        second, 98.0% to the common unitholders, pro rata, and 2.0% to our general partner, until the capital account for each common unit is equal to the sum of: (1) the unrecovered initial unit price; (2) the amount of the minimum quarterly distribution for the quarter during which our liquidation occurs; and (3) any unpaid arrearages in payment of the minimum quarterly distribution;

        third, 98.0% to the subordinated unitholders, pro rata, and 2.0% to our general partner, until the capital account for each subordinated unit is equal to the sum of: (1) the unrecovered initial unit price; and (2) the amount of the minimum quarterly distribution for the quarter during which our liquidation occurs;

        fourth, 98.0% to all unitholders, pro rata, and 2.0% to our general partner, until we allocate under this paragraph an amount per unit equal to: (1) the sum of the excess of the first target distribution per unit over the minimum quarterly distribution per unit for each quarter of our existence; less (2) the cumulative amount per unit of any distributions of available cash from operating surplus in excess of the minimum quarterly distribution per unit that we distributed 98.0% to the unitholders, pro rata, and 2.0% to our general partner, for each quarter of our existence;

        fifth, 85.0% to all unitholders, pro rata, and 15.0% to our general partner, until we allocate under this paragraph an amount per unit equal to: (1) the sum of the excess of the second target distribution per unit over the first target distribution per unit for each quarter of our existence; less (2) the cumulative amount per unit of any distributions of available cash from operating surplus in excess of the first target distribution per unit that we distributed 85.0% to the unitholders, pro rata, and 15.0% to our general partner for each quarter of our existence;

        sixth, 75.0% to all unitholders, pro rata, and 25.0% to our general partner, until we allocate under this paragraph an amount per unit equal to: (1) the sum of the excess of the third target distribution per unit over the second target distribution per unit for each quarter of our existence; less (2) the cumulative amount per unit of any distributions of available cash from operating surplus in excess of the second target distribution per unit that we distributed 75.0% to the unitholders, pro rata, and 25.0% to our general partner for each quarter of our existence; and

        thereafter, 50.0% to all unitholders, pro rata, and 50.0% to our general partner.

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              The percentage interests set forth above for our general partner include its 2.0% general partner interest and assume our general partner has not transferred the incentive distribution rights.


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              If the liquidation occurs after the end of the subordination period, the distinction between common and subordinated units will disappear, so that clause (3) of the second bullet point above and all of the third bullet point above will no longer be applicable.

      Manner of Adjustments for Losses

              If our liquidation occurs before the end of the subordination period, after making allocations of loss to the general partner and the unitholders in a manner intended to offset in reverse order the allocations of gains that have previously been allocated, we will generally allocate any loss to our general partner and the unitholders in the following manner:

        first, 98.0% to holders of subordinated units in proportion to the positive balances in their capital accounts and 2.0% to our general partner, until the capital accounts of the subordinated unitholders have been reduced to zero;

        second, 98.0% to the holders of common units in proportion to the positive balances in their capital accounts and 2.0% to our general partner, until the capital accounts of the common unitholders have been reduced to zero; and

        thereafter, 100.0% to our general partner.

              If the liquidation occurs after the end of the subordination period, the distinction between common and subordinated units will disappear, so that all of the first bullet point above will no longer be applicable.

      Adjustments to Capital Accounts

              Our partnership agreement requires that we make adjustments to capital accounts upon the issuance of additional units. In this regard, our partnership agreement specifies that we allocate any unrealized and, for U.S. federal income tax purposes, unrecognized gain resulting from the adjustments to the unitholders and the general partner in the same manner as we allocate gain upon liquidation. In the event that we make positive adjustments to the capital accounts upon the issuance of additional units, our partnership agreement requires that we generally allocate any later negative adjustments to the capital accounts resulting from the issuance of additional units or upon our liquidation in a manner which results, to the extent possible, in the partners' capital account balances equaling the amount which they would have been if no earlier positive adjustments to the capital accounts had been made. By contrast to the allocations of gain, and except as provided above, we generally will allocate any unrealized and unrecognized loss resulting from the adjustments to capital accounts upon the issuance of additional units to the unitholders and our general partner based on their respective percentage ownership of us. In this manner, prior to the end of the subordination period, we generally will allocate any such loss equally with respect to our common and subordinated units. In the event we make negative adjustments to the capital accounts as a result of such loss, future positive adjustments resulting from the issuance of additional units will be allocated in a manner designed to reverse the prior negative adjustments, and special allocations will be made upon liquidation in a manner that results, to the extent possible, in our unitholders' capital account balances equaling the amounts they would have been if no earlier adjustments for loss had been made.


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      SELECTED HISTORICAL CONSOLIDATED AND CONDENSED CONSOLIDATED AND PRO FORMA CONDENSED 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 March 31, 2006 and December 31, 2006 and 2007 and for the years ended March 31, 2006 and nine months ended December 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 as of and for the year ended December 31, 2008 was restated to reflect certain selling, general and administrative expenses within the statement of operations, rather than as a distribution to members in the statement of financial position. The selected historical consolidated financial data presented as of December 31, 2008 and 2009 and for the years ended December 31, 2007, 2008 and 2009 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,June 30, 2010 and for the threesix months ended March 31,June 30, 2009 and 2010 is derived from the unaudited historical condensed consolidated financial statements of Rhino Energy LLC that are included elsewhere in this prospectus. The selected historical condensed consolidated financial data presented as of March 31,June 30, 2009 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 selected pro forma condensed consolidated financial data presented for the year ended December 31, 2009 and as of and for the threesix months ended March 31,June 30, 2010 is derived from our unaudited pro forma condensed consolidated financial statements included elsewhere in this prospectus. Our unaudited pro forma condensed consolidated financial statements give pro forma effect to:

        the contribution by Wexford of its membership interests in Rhino Energy LLC to us;

        the issuance by us to Rhino Energy Holdings LLC of an aggregate of 8,647,0009,153,000 common units and 12,397,000 subordinated units;

        the issuance by us to our general partner of a 2.0% general partner interest in us;us, a capital contribution by our general partner to us and the use of the contribution as described under "Use of Proceeds"; and

        the issuance by us to the public of 3,750,0003,244,000 common units and the use of the net proceeds from this offering as described under "Use of Proceeds."

              The unaudited pro forma condensed consolidated statement of financial position assumes the items listed above occurred as of March 31,June 30, 2010. The unaudited pro forma condensed consolidated statements of operations data for the year ended December 31, 2009 and the threesix months ended March 31,June 30, 2010 assume the items listed above occurred as of January 1, 2009. 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 partnership.

              For a detailed discussion of the selected historical consolidated financial information contained in 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" and the audited historical


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      consolidated financial statements of Rhino Energy LLC and our unaudited pro forma condensed consolidated financial statements included elsewhere in this prospectus. Among other things,


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      the historical consolidated and unaudited pro forma condensed 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 represents net income before interest expense, income taxes and depreciation, depletion and amortization. This measure is not calculated or presented in accordance with GAAP. We explain this measure under "—Non-GAAP Financial Measure" and reconcile it to its most directly comparable financial measures calculated and presented in accordance with GAAP.



       Rhino Energy LLC Historical Rhino Resource Partners LP
      Pro Forma Condensed
      Consolidated
       
       Rhino Energy LLC Historical Rhino Resource Partners LP
      Pro Forma Condensed
      Consolidated
       


       Consolidated Condensed
      Consolidated
        
        
       
       Consolidated Condensed
      Consolidated
        
        
       


       Year Ended
      March 31,
       Nine Months
      Ended
      December 31,
       Year Ended December 31, Three Months Ended
      March 31,
       Year Ended
      December 31,
       Three Months
      Ended
      March 31,
       
       Year Ended
      March 31,
       Nine Months
      Ended
      December 31,
       Year Ended December 31, Six Months Ended
      June 30,
       Year Ended
      December 31,
       Six Months
      Ended
      June 30,
       


        
       2008
      (as restated)
        
       
        
       2008
      (as restated)
        
       


       2006 2006 2007 2009 2009 2010 2009 2010 
       2006 2006 2007 2009 2009 2010 2009 2010 


       (in thousands, except per unit data)
       
       (in thousands, except per unit data)
       

      Statement of Operations Data:

      Statement of Operations Data:

       

      Statement of Operations Data:

       

      Total revenues

      Total revenues

       $363,960 $300,839 $403,452 $438,924 $419,790 $116,706 $66,603 $419,790 $66,603 

      Total revenues

       $363,960 $300,839 $403,452 $438,924 $419,790 $226,095 $145,031 $419,790 $145,031 

      Costs and expenses:

      Costs and expenses:

       

      Costs and expenses:

       

      Cost of operations (exclusive of depreciation, depletion and amortization shown separately below)

       291,208 241,185 318,405 364,912 336,335 98,317 46,352 336,335 46,352 

      Cost of operations (exclusive of depreciation, depletion and amortization shown separately below)

       291,208 241,185 318,405 364,912 336,335 183,518 104,192 336,335 104,192 

      Freight and handling costs

       6,343 2,768 4,021 10,223 3,990 938 673 3,990 673 

      Freight and handling costs

       6,343 2,768 4,021 10,223 3,990 1,976 1,444 3,990 1,444 

      Depreciation, depletion and amortization

       13,744 28,471 30,750 36,428 36,279 9,974 7,765 36,279 7,765 

      Depreciation, depletion and amortization

       13,744 28,471 30,750 36,428 36,279 19,872 15,803 36,279 15,803 

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

       17,129 18,573 15,370 19,042 16,754 4,376 3,678 16,754 3,678 

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

       17,129 18,573 15,370 19,042 16,754 8,989 7,604 16,754 7,604 

      (Gain) loss on sale of assets

       (377) 746 (944) 451 1,710  (1) 1,710 (1)

      (Gain) loss on sale of assets

       (377) 746 (944) 451 1,710 1,288 (47) 1,710 (47)
                                             
       

      Total costs and expenses

       328,047 291,742 367,602 431,056 395,069 113,605 58,466 395,069 58,466  

      Total costs and expenses

       328,047 291,742 367,602 431,056 395,069 215,643 128,996 395,069 128,996 
                                             

      Income from operations

      Income from operations

       35,913 9,096 35,849 7,868 24,721 3,101 8,136 24,721 8,136 

      Income from operations

       35,913 9,096 35,849 7,868 24,721 10,452 16,035 24,721 16,035 

      Interest and other income (expense):

      Interest and other income (expense):

       

      Interest and other income (expense):

       

      Interest expense

       (4,976) (6,498) (5,579) (5,501) (6,222) (1,170) (1,471) (4,291) 992 

      Interest expense

       (4,976) (6,498) (5,579) (5,501) (6,222) (2,891) (2,781) (4,271) (1,875)

      Interest income

       412 312 317 149 71 87 8 71 8 

      Interest income

       412 312 317 149 71 69 18 71 18 

      Equity in net income (loss) of unconsolidated affiliate(1)

          (1,587) 893 (43) (130) 893 (130)

      Equity in net income (loss) of unconsolidated affiliate(1)

          (1,587) 893 (268) 414 893 414 

      Other—net

       491 272        

      Other—net

       491 272           
                                             

      Total interest and other expense

      Total interest and other expense

       (4,073) (5,914) (5,263) (6,939) (5,259) (1,125) (1,592) (3,327) (1,114)

      Total interest and other expense

       (4,073) (5,914) (5,263) (6,939) (5,259) (3,089) (2,349) (3,307) (1,443)
                                             

      Income before income tax expense

      Income before income tax expense

       31,840 3,182 30,588 929 19,462 1,976 6,544 21,394 7,023 

      Income before income tax expense

       31,840 3,182 30,588 929 19,462 7,362 13,686 21,413 14,592 

      Income tax expense (benefit)

      Income tax expense (benefit)

       178 125 (126)       

      Income tax expense (benefit)

       178 125 (126)       
                                             

      Net income

      Net income

       $31,661 $3,057 $30,714 $929 $19,462 $1,976 $6,544 $21,394 $7,023 

      Net income

       $31,661 $3,057 $30,714 $929 $19,462 $7,362 $13,686 $21,413 $14,592 

      Net income per limited partner unit, basic:

      Net income per limited partner unit, basic:

       

      Net income per limited partner unit, basic:

       

      Common units

       $1.306 $0.360 

      Common units

       $1.306 $0.581 

      Subordinated units

       $0.385 $0.196 

      Subordinated units

       $0.387 $0.573 

      Net income per limited partner unit, diluted:

      Net income per limited partner unit, diluted:

       

      Net income per limited partner unit, diluted:

       

      Common units

       $1.304 $0.358 

      Common units

       $1.305 $0.578 

      Subordinated units

       $0.385 $0.196 

      Subordinated units

       $0.387 $0.573 

      Weighted average number of limited partner units outstanding, basic:

      Weighted average number of limited partner units outstanding, basic:

       

      Weighted average number of limited partner units outstanding, basic:

       

      Common units

       12,411,479 12,447,417 

      Common units

       12,397,000 12,397,000 

      Subordinated units

       12,397,000 12,397,000 

      Subordinated units

       12,397,000 12,397,000 

      Weighted average number of limited partner units outstanding, diluted:

      Weighted average number of limited partner units outstanding, diluted:

       

      Weighted average number of limited partner units outstanding, diluted:

       

      Common units

       12,397,000 12,397,000 

      Common units

       12,410,073 12,445,073 

      Subordinated units

       12,397,000 12,397,000 

      Subordinated units

       12,397,000 12,397,000 

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       Rhino Energy LLC Historical Rhino Resource Partners LP
      Pro Forma Condensed
      Consolidated
       
       Rhino Energy LLC Historical Rhino Resource Partners LP
      Pro Forma Condensed
      Consolidated
       


       Consolidated Condensed
      Consolidated
        
        
       
       Consolidated Condensed
      Consolidated
        
        
       


       Year Ended
      March 31,
       Nine Months
      Ended
      December 31,
       Year Ended December 31, Three Months Ended
      March 31,
       Year Ended
      December 31,
       Three Months
      Ended
      March 31,
       
       Year Ended
      March 31,
       Nine Months
      Ended
      December 31,
       Year Ended December 31, Six Months Ended
      June 30,
       Year Ended
      December 31,
       Six Months
      Ended
      June 30,
       


        
       2008
      (as restated)
        
       
        
       2008
      (as restated)
        
       


       2006 2006 2007 2009 2009 2010 2009 2010 
       2006 2006 2007 2009 2009 2010 2009 2010 


       (in thousands, except per ton data)
       
       (in thousands, except per ton data)
       

      Statement of Cash Flows Data:

      Statement of Cash Flows Data:

       

      Statement of Cash Flows Data:

       

      Net cash provided by (used in):

      Net cash provided by (used in):

       

      Net cash provided by (used in):

       

      Operating activities

       $32,892 $36,860 $52,493 $57,211 $41,495 $3,274 $4,555     

      Operating activities

       $32,892 $36,860 $52,493 $57,211 $41,495 $20,222 $24,871     

      Investing activities

       $(34,613)$(28,828)$(28,098)$(106,638)$(27,345)$(11,732)$(6,541)     

      Investing activities

       $(34,613)$(28,828)$(28,098)$(106,638)$(27,345)$(19,424)$(11,588)     

      Financing activities

       $(1,887)$(9,141)$(21,192)$47,781 $(15,401)$7,028 $1,647     

      Financing activities

       $(1,887)$(9,141)$(21,192)$47,781 $(15,401)$(2,292)$(13,781)     

      Other Financial Data:

      Other Financial Data:

       

      Other Financial Data:

       

      EBITDA

      EBITDA

       $50,560 $38,151 $66,917 $42,858 $61,964 $13,119 $15.779 $61,964 $15,779 

      EBITDA

       $50,560 $38,151 $66,917 $42,858 $61,964 $30,125 $32,270 $61,964 $32,270 

      Capital expenditures (1)

      Capital expenditures (1)

       $66,373 $42,393 $32,773 $92,741 $29,657 $10,965 $6,637 $29,657 $6,637 

      Capital expenditures (1)

       $66,373 $42,393 $32,773 $92,741 $29,657 $18,825 $11,498 $29,657 $11,498 

      Balance Sheet Data (at period end):

      Balance Sheet Data (at period end):

       

      Balance Sheet Data (at period end):

       

      Cash and cash equivalents

      Cash and cash equivalents

       $1,489 $380 $3,583 $1,937 $687 $508 $347 $687 $347 

      Cash and cash equivalents

       $1,489 $380 $3,583 $1,937 $687 $443 $188   $188 

      Property and equipment, net

      Property and equipment, net

       $180,267 $197,056 $211,657 $282,863 $270,680 $283,685 $269,603 $270,680 $269,603 

      Property and equipment, net

       $180,267 $197,056 $211,657 $282,863 $270,680 $278,124 $266,357   $266,357 

      Total assets

      Total assets

       $246,759 $248,195 $275,992 $352,536 $339,985 $369,112 $347,488 $339,985 $347,488 

      Total assets

       $246,759 $248,195 $275,992 $352,536 $339,985 $350,652 $340,897   $340,897 

      Total liabilities

      Total liabilities

       $154,028 $153,307 $158,152 $234,225 $201,584 $248,825 $202,543 $134,634 $135,593 

      Total liabilities

       $154,028 $153,307 $158,152 $234,225 $201,584 $225,027 $188,811   $121,178 

      Total debt

      Total debt

       $87,764 $88,571 $83,954 $138,027 $122,137 $145,107 $123,833 $55,187 $56,883 

      Total debt

       $87,764 $88,571 $83,954 $138,027 $122,137 $137,146 $108,454   $40,821 

      Members'/partners' equity

      Members'/partners' equity

       $92,731 $94,887 $117,841 $118,311 $138,401 $120,287 $144,944 $205,351 $211,894 

      Members'/partners' equity

       $92,731 $94,887 $117,841 $118,311 $138,401 $125,625 $152,086   $219,719 

      Operating Data (2):

      Operating Data (2):

       

      Operating Data (2):

       

      Tons of coal sold

      Tons of coal sold

       7,900 6,223 8,159 7,977 6,699 1,939 949 6,699 949 

      Tons of coal sold

       7,900 6,223 8,159 7,977 6,699 3,696 2,042 6,699 2,042 

      Tons of coal produced/purchased

      Tons of coal produced/purchased

       7,950 6,182 8,024 8,017 6,732 1,991 1,044 6,732 1,044 

      Tons of coal produced/purchased

       7,950 6,182 8,024 8,017 6,732 3,742 2,176 6,732 2,176 

      Coal revenues per ton (3)

      Coal revenues per ton (3)

       $44.48 $47.31 $48.30 $51.25 $59.98 $58.33 $65.98 $59.98 $65.98 

      Coal revenues per ton (3)

       $44.48 $47.31 $48.30 $51.25 $59.98 $59.06 $66.96 $59.98 $66.96 

      Cost of operations per ton (4)

      Cost of operations per ton (4)

       $36.89 $38.28 $39.02 $45.75 $50.21 $50.69 $48.82 $50.21 $48.82 

      Cost of operations per ton (4)

       $36.89 $38.28 $39.02 $45.75 $50.21 $49.66 $51.02 $50.21 $51.02 

      (1)
      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 Condensed
      Consolidated
       
       
       Year Ended
      March 31,
       Nine Months
      Ended
      December 31,
       Year Ended December 31, Three Months Ended
      March 31,
       
       
       2006 2006 2007 2008 2009 2009 2010 
       
       (in thousands)
       
       

      Reconciliation of total capital expenditures to net cash used for capital expenditures:

                            
       

      Additions to property, plant and equipment

       $31,485 $32,701 $14,599 $78,076 $27,836 $9,144 $6,637 
       

      Acquisitions of coal companies and coal properties

        5,000    18,174  14,665  1,821  1,821   
                      
       

      Net cash used for capital expenditures

        36,485  32,701  32,773  92,741  29,657  10,965  6,637 
                      
       

      Plus:

                            
        

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

        29,888  9,692           
                      
       

      Total capital expenditures

       $66,373 $42,393 $32,773 $92,741 $29,657 $10,965 $6,637 
                      
       
       Rhino Energy LLC Historical 
       
       Consolidated Condensed
      Consolidated
       
       
       Year Ended
      March 31,
       Nine Months
      Ended
      December 31,
       Year Ended December 31, Six Months Ended
      June 30,
       
       
       2006 2006 2007 2008 2009 2009 2010 
       
       (in thousands)
       
       

      Reconciliation of total capital expenditures to net cash used for capital expenditures:

                            
       

      Additions to property, plant and equipment

       $31,485 $32,701 $14,599 $78,076 $27,836 $17,004 $11,440 
       

      Acquisitions of coal companies and coal properties

        5,000    18,174  14,665      58 
       

      Acquisition of roof bolt manufacturing company

                1,821  1,821   
                      
       

      Net cash used for capital expenditures

        36,485  32,701  32,773  92,741  29,657  18,825  11,498 
                      
       

      Plus:

                            
        

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

        29,888  9,692           
                      
       

      Total capital expenditures

       $66,373 $42,393 $32,773 $92,741 $29,657 $18,825 $11,498 
                      
      (2)
      In May 2008, we entered into a joint venture with an affiliate of Patriot that acquired the Rhino Eastern mining complex, which commenced production in August 2008. We have a 51% membership interest in, and serve as manager for, the joint venture. The operating data do not include data with respect to the Rhino Eastern mining complex. The joint venture produced and sold approximately 0.2 million tons and approximately 0.1 million tons of premium mid-vol metallurgical coal for the year ended December 31, 2009 and the threesix months ended March 31,June 30, 2010, respectively.
      (3)
      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.
      (4)
      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.

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      Non-GAAP Financial Measure

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

        our financial performance without regard to financing methods, capital structure or income taxes;

        our ability to generate cash sufficient to make distributions to our unitholders; and

        our ability to incur and service debt and to fund capital expenditures.

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

              EBITDA as presented below may not be comparable to similarly titled measures of other companies. The following table presents a reconciliation of EBITDA to the most directly comparable GAAP financial measures, on a historical basis and pro forma basis, as applicable, for each of the periods indicated.indicated:


       Rhino Energy LLC Historical Rhino Resource Partners LP
      Pro Forma Condensed
      Consolidated
       


       Rhino Energy LLC Historical Rhino Resource Partners LP
      Pro Forma Condensed
      Consolidated
       
       Consolidated Condensed
      Consolidated
        
        
       


       Consolidated Condensed
      Consolidated
        
        
       
       Year
      Ended
      March 31,
       Nine Months
      Ended
      December 31,
       Year Ended December 31,  
        
       Year Ended
      December 31,
       Six Months
      Ended
      June 30,
       


       Year
      Ended
      March 31,
       Nine Months
      Ended
      December 31,
       Year Ended December 31, Three Months Ended March 31, Year Ended
      December 31,
       Three Months
      Ended
      March 31,
       
       Six Months Ended June 30, 


        
       2008
      (as restated)
        
       
        
       2008
      (as restated)
        
      Six Months
      Ended
      June 30,


       2006 2006 2007 2009 2009 2010 2009 2010 
       2006 2006 2007 2009 2009 2010 2009 2010


       (in thousands)
       
       (in thousands)

      Reconciliation of EBITDA to net income:

      Reconciliation of EBITDA to net income:

       

      Reconciliation of EBITDA to net income:

       

      Net income

      Net income

       $31,661 $3,057 $30,714 $929 $19,462 $1,976 $6,544 $21,394 $7,023 

      Net income

       $31,661 $3,057 $30,714 $929 $19,462 $7,362 $13,686 $21,413 $14,592 

      Plus:

      Plus:

       

      Plus:

       

      Depreciation, depletion and amortization

       13,744 28,471 30,750 36,428 36,279 9,974 7,765 36,279 7,765 

      Depreciation, depletion and amortization

       13,744 28,471 30,750 36,428 36,279 19,872 15,803 36,279 15,803 

      Interest expense

       4,976 6,498 5,579 5,501 6,222 1,170 1,471 4,291 992 

      Interest expense

       4,976 6,498 5,579 5,501 6,222 2,891 2,781 4,271 1,875 

      Income tax expense

       178 125           

      Income tax expense

       178 125        

      Less:

      Less:

       

      Less:

       

      Income tax benefit

         126       

      Income tax benefit

         126       
                                             

      EBITDA

      EBITDA

       $50,560 $38,151 $66,917 $42,858 $61,964 $13,119 $15,779 $61,964 $15,779 

      EBITDA

       $50,560 $38,151 $66,917 $42,858 $61,964 $30,125 $32,270 $61,964 $32,270 
                                             

      Reconciliation of EBITDA to net cash provided by (used in) operating activities:

      Reconciliation of EBITDA to net cash provided by (used in) operating activities:

       

      Reconciliation of EBITDA to net cash provided by (used in) operating activities:

       

      Net cash provided by (used in) operating activities

      Net cash provided by (used in) operating activities

       $32,892 $36,860 $52,493 $57,211 $41,495 $3,274 $4,555 

      Net cash provided by (used in) operating activities

       $32,892 $36,860 $52,493 $57,211 $41,495 $20,222 $24,871 

      Plus:

      Plus:

       

      Plus:

       

      Increase in net operating assets

       16,447 893 10,553  17,190 9,601 10,828 

      Increase in net operating assets

       16,447 893 10,553  17,190 10,290 5,827 

      Decrease in provision for doubtful accounts

        283 175     

      Decrease in provision for doubtful accounts

        283 175     

      Gain on sale of assets

       377  944    1 

      Gain on sale of assets

       377  944    47 

      Gain on retirement of advance royalties

       237  115     

      Gain on retirement of advance royalties

       237  115   77  

      Interest expense

       4,976 6,498 5,579 5,501 6,222 1,170 1,471 

      Interest expense

       4,976 6,498 5,579 5,501 6,222 2,891 2,781 

      Income tax expense

       178 125        

      Income tax expense

       178 125      

      Settlement of litigation

           1,773   

      Settlement of litigation

           1,773   

      Equity in net income of unconsolidated affiliate

           893   

      Equity in net income of unconsolidated affiliate

           893  414 

      Less:

      Less:

       

      Less:

       

      Decrease in net operating assets

          10,440    

      Decrease in net operating assets

          10,440    

      Accretion on interest-free debt

       321 255 360 569 200 44 49 

      Accretion on interest-free debt

       321 255 360 569 200 193 98 

      Amortization of advance royalties

       2,187 1,099 700 471 215 83 276 

      Amortization of advance royalties

       2,187 1,099 700 471 215 156 374 

      Increase in provision for doubtful accounts

       354    19   

      Increase in provision for doubtful accounts

       354    19   

      Loss on sale of assets

        746  451 1,710   

      Loss on sale of assets

        746  451 1,710 1,288  

      Loss on retirement of advance royalties

        2,995  45 712  78 

      Loss on retirement of advance royalties

        2,995  45 712  113 

      Income tax benefit

         126     

      Income tax benefit

         126     

      Accretion on asset retirement obligations

       1,686 1,412 1,757 2,709 2,753 756 542 

      Accretion on asset retirement obligations

       1,686 1,412 1,757 2,709 2,753 1,450 1,085 

      Equity in net loss of unconsolidated affiliate

          1,587  43 130 

      Equity in net loss of unconsolidated affiliate

          1,587  268  

      Payment of abandoned public offering expenses (a)

          3,582    

      Payment of abandoned public offering expenses (a)

          3,582    
                                         

      EBITDA

      EBITDA

       $50,560 $38,151 $66,917 $42,858 $61,964 $13,119 $15,779 

      EBITDA

       $50,560 $38,151 $66,917 $42,858 $61,964 $30,125 $32,270 
                                         

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

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      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 subsidiaries, in conjunction with the historical consolidated financial statements of Rhino Energy LLC and the unaudited pro forma condensed consolidated financial statements of Rhino Resource Partners LP included elsewhere in this prospectus. Among other things, those historical consolidated and unaudited pro forma condensed consolidated financial statements include more detailed information regarding the basis of presentation for the following information.

      Overview

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

              For the year ended December 31, 2009, we generated revenues of approximately $419.8 million and net income of approximately $19.5 million. For the threesix months ended March 31,June 30, 2010, we generated revenues of approximately $66.6$145.0 million and net income of approximately $6.5$13.7 million. As of July 13,August 23, 2010, we had sales commitments for approximately 99%97% and 80%69% of our estimated coal production (including purchased coal to supplement our production and excluding results from the joint venture) for the year ending December 31, 2010 and the twelve months ending JuneSeptember 30, 2011, respectively.

              We have a geographically diverse asset base with coal reserves located in Central Appalachia, Northern Appalachia, the Illinois Basin and the Western Bituminous region. As of March 31, 2010, we controlled an estimated 285.4 million tons of proven and probable coal reserves, consisting of an estimated 272.9 million tons of steam coal and an estimated 12.5 million tons of metallurgical coal. In addition, as of March 31, 2010, we controlled an estimated 122.2 million tons of non-reserve coal deposits. As of March 31, 2010, Rhino Eastern LLC, a joint venture in which we have a 51% membership interest and for which we serve as manager, controlled an estimated 22.4 million tons of proven and probable coal reserves at the Rhino Eastern mining complex located in Central Appalachia, consisting entirely of premium mid-vol and low-vol metallurgical coal, and an estimated 34.3 million tons of non-reserve coal deposits. Our and the joint venture's proven and probable coal reserves and non-reserve coal deposits were the same in all material respects as of December 31, 2009. We currently operate twelveeleven mines, including sevensix underground and five surface mines, located in Kentucky, Ohio, Colorado and West Virginia. In addition, the joint venture currently operates one underground mine in West Virginia. The number of mines that we operate may vary from time to time depending on a number of factors, including the demand for and price of coal, depletion of economically recoverable reserves and availability of experienced labor. Excluding results from the joint venture, for the year ended December 31, 2009, we produced approximately 4.7 million tons of coal, purchased approximately 2.0 million tons of coal and sold approximately 6.7 million tons of coal, approximately 99% of which was pursuant to supply contracts. Excluding results from the joint venture, for the threesix months ended March 31,June 30, 2010, we produced approximately 1.02.1 million tons of coal and sold approximately 0.92.0 million tons of coal, approximately 99%97% of which were pursuant to supply contracts. Additionally, the joint venture produced and sold approximately 0.2 million tons and approximately 0.1 million


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      tons of premium mid-vol metallurgical coal for the year ended December 31, 2009 and the three


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      six months ended March 31,June 30, 2010, respectively. We expect to continue selling a significant portion of our coal under supply contracts.

              Since our predecessor's formation in 2003, we have significantly grown our coal reserves. Since April 2003, we have completed numerous coal asset acquisitions with a total purchase price of approximately $208.3 million. Through these acquisitions and coal lease transactions, we have substantially increased$223.3 million, including our proven and probable coal reserves and non-reserve coal deposits. We expect to complete the acquisition in August 2010 of certain mining assets of C.W. Mining Company out of bankruptcy for approximately $15.0 million.bankruptcy. The assets to be acquired are located in Emery and Carbon Counties, Utah and include coal reserves and non-reserve coal deposits, underground mining equipment and infrastructure, an overland belt conveyor system, a loading facility and support facilities. We intend to fund the asset acquisition with borrowings underThrough these acquisitions and coal lease transactions, we have substantially increased our credit agreement.proven and probable coal reserves and non-reserve coal deposits. 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.

              Our results of operations in the near term could be impacted by a number of factors, including (1) adverse weather conditions and natural disasters, (2) poor mining conditions resulting from geological conditions or the effects of prior mining, (3) equipment problems at mining locations, (4) the availability of transportation for coal shipments or (5) the availability and costs of key supplies and commodities such as steel, diesel fuel and explosives. On a long-term basis, our results of operations could be impacted by, among other factors, (1) changes in governmental regulation 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 favorable supply contracts. We have historically sold a majority of our coal through supply contracts and anticipate that we will continue to do so. During the year ended December 31, 2008, we entered into certain sales contracts at favorable prices. Sales under these contracts had a significant impact on revenues for the year ended December 31, 2009 and for threesix months ended March 31,June 30, 2010. We have remaining commitments under these contracts of approximately 0.9 million tons of coal at an average price of approximately $90 per ton for the remainder of the year ended December 31, 2010 and 0.4 million tons at an average price of $92 per ton for each of the years ended December 31, 2011, 2012 and 2013.

              We conduct business through four reportable business segments: Central Appalachia, Northern Appalachia, Eastern Met and Other. Our Central Appalachia segment consists of three mining complexes: Tug River, Rob Fork and Deane, which, as of March 31,June 30, 2010, together included four underground mines, three surface mines and three preparation plants and loadout facilities in eastern Kentucky and southern West Virginia. Our Northern Appalachia segment consists of the Hopedale mining complex, the Sands Hill mining complex, the Leesville field and the Springdale field. The Hopedale mining complex, located in southern Ohio, included one underground mine and one preparation plant and loadout facility as of March 31,June 30, 2010. Our Sands Hill mining complex, located in northern Ohio, included two surface mines, a preparation plant and a river terminal as of March 31,June 30, 2010. The Eastern Met segment includes our 51% equity interest in the results of operations of the joint venture, which owns the Rhino Eastern mining complex, located in West Virginia, and for which we serve as manager. ThisAs of June 30, 2010, this complex iswas comprised of a singleone underground mine and a preparation plant and loadout facility (owned by our joint venture partner). For the year ended December 31, 2009 and the threesix months ended March 31,June 30, 2010, our Other segment included the results of our operations of our underground mine in the Western Bituminous region, our coal reserves in the Illinois Basin and our ancillary businesses. These ancillary businesses include a roof bolt manufacturing operation


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      businesses. These ancillaryand various businesses that provide support services such as reclamation, maintenance and transportation, the cost of which is reflected in our cost of operations.

      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. 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. Please read "The Coal Industry." In addition, our results of operations depend on the cost of coal production. We are experiencing increased operating costs for steel, health care and insurance. 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 federal levels that have resulted in increased scrutiny of current safety practices at all mining operations and at underground mining operations in particular. Many states have proposed or passed more stringent mine safety laws and regulations and increased sanctions for non-compliance, which imposes additional costs on coal producers.

        Delays in obtaining and renewing permits.  Numerous governmental permits and 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 or renewal of permits. Such delays in obtaining and renewing permits have a 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, diesel fuel, explosives and other raw materials. The coal industry has seen a stabilization of many of these prices in the past year. This trend has continued through March 2010, when the price of steel began to escalate. ContinuedHowever, any future escalation of the costs of raw materials may have a significant impact on our results of operations.

        Changes in the amount of coal consumed by producers of electricity.  We sell a large portion of the coal we produce to electric utilities. The demand for coal by the electric utility industry is affected primarily by the demand for electricity as well as the price and availability of competing alternative fuels that these utilities may use to generate power. The regulation of greenhouse gas emissions and other government mandates may also force these utilities to accelerate the use of fuels other than coal. Some states have enacted legislation that requires electricity suppliers to rely on renewable energy sources in generating a certain percentage of power. These actions, as well as others intended to encourage the use of renewable energy sources (including tax credits), could make these alternative fuels more competitive with coal.



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        Shortage of skilled labor and rising labor and benefit costs.  The coal industry is experiencing a shortage of skilled labor as well as rising labor and benefit costs, due in

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          large part to demographic changes as existing miners retire at a faster rate than new miners are entering the workforce. If the shortage of experienced labor continues or worsens or coal producers are unable to train enough skilled laborers, there could be an adverse impact on labor productivity and an increase in our costs, our ability to expand production may be limited.

              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, including (1) EBITDA, (2) coal revenues per ton and (3) cost of operations per ton.

              EBITDA. The discussion of our results of operations below includes references to, and analysis of, our segments' EBITDA results. EBITDA represents net income before deducting interest expense, income taxes and depreciation, depletion and amortization. EBITDA is used by management primarily as a measure of our segments' operating performance. 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 for each of the periods indicated.

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

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

      Public Company Expenses

              We believe that our selling, general and administrative expenses will increase as a result of becoming a publicly traded partnership 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. 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.

      The Joint Venture

              We have historically accounted for the results of operations for the joint venture, Rhino Eastern LLC, using the equity method. Using the equity method, we recognize our proportionate share of the investees' net income as a single component of other income. For this reason, the historical and pro forma results of operations reported for the joint venture are only included in


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      our presentation and analyses of net income and EBITDA. We consider the operations at the Rhino Eastern mining complex as one of our reportable segments and, accordingly, present limited additional detail related to the results of operations of our Rhino Eastern mining complex in Note 15 to the Rhino Energy LLC unaudited historical condensed consolidated


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      financial statements and Note 17 to the Rhino Energy LLC audited historical consolidated financial statements included elsewhere in this prospectus.

      Restatement of Audited Consolidated Financial Statements for the Year Ended December 31, 2008

              Subsequent to the audit of our consolidated financial statements for the year ended December 31, 2009, our independent registered public accounting firm identified a deficiency in our internal control over financial reporting as a result of a restatement of our consolidated financial statements as of December 31, 2008 which constituted a material weakness. For information on the restatement of our audited consolidated financial statements as of and for the year ended December 31, 2008, please read Note 18 to the Rhino Energy LLC audited historical audited consolidated financial statements included elsewhere in this prospectus and "Risk Factors—Risks Inherent in an Investment in Us—We cannot provide absolute assurance as to our ability to establish and maintain effective internal controls in accordance with applicable federal securities laws and regulations, and we may incur significant costs in our efforts." We have taken measures to improve our internal controlcontrols over financial reporting to help ensure that material weaknesses resulting in a material misstatement of our financial statements do not occur in the future.

      ThreeSix Months Ended March 31,June 30, 2010 Compared to ThreeSix Months Ended March 31,June 30, 2009

              Summary. For the threesix months ended March 31,June 30, 2010, our total revenues decreased to $66.6$145.0 million from $116.7$226.1 million for the threesix months ended March 31,June 30, 2009. The decrease was primarily due to a decrease in demand for our production of both steam coal and metallurgical coal. We reduced our overall production of coal by 0.7 million tons to 2.1 million tons for the six months ended June 30, 2010 as various consumerscompared to 2.8 million tons for the six months ended June 30, 2009. We suspended or reduced production at specific mines in response to market conditions and businesses used less electricity and a decrease in demand for our metallurgical coalhave the ability to restart production at these operations quickly as a result of decreased steel production. As a result of this decreased demand,market conditions improve. In addition, we sold 1.0purchased 0.1 million tons of coal for the threesix months ended March 31,June 30, 2010 as compared to 1.1 million tons of purchased coal for the six months ended June 30, 2009 and increased our coal inventory by 0.1 million tons. This increase in inventory was the result of temporary delays in rail service.

              As a result of these changes, we sold 2.0 million tons of coal for the six months ended June 30, 2010, which is 1.01.7 million fewer tons, or 51.1%44.7% less, than the 2.03.7 million tons of coal sold for the threesix months ended March 31, 2009. In response to the decrease in demand, we reduced our overall production of coal by 0.6 million tons to 1.0 million tons for the three months ended March 31, 2010 as compared to 1.6 million tons for the three months ended March 31, 2009. We reduced production by idling certain less profitable surface operations. In addition, we did not purchase any coal for the three months ended March 31, 2010 as compared to 0.4 million tons of purchased coal for the three months ended March 31,June 30, 2009. Despite the decrease in the number of tons that we produced and sold, both net income and EBITDA increased for the threesix months ended March 31,June 30, 2010 from the threesix months ended March 31,June 30, 2009. Net income increased to $6.6 million from $2.0$13.7 million for the threesix months ended March 31,June 30, 2010 from $7.4 million for the six months ended June 30, 2009, and EBITDA increased to $15.8$32.3 million for the threesix months ended March 31,June 30, 2010 from $13.1$30.1 million for the threesix months ended March 31,June 30, 2009. These increases in net income and EBITDA were due to the sale of higher quality coal and to our successful efforts to control cost of operations.


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              Tons Sold. The following table presents tons of coal sold by reportable segment for the threesix months ended March 31,June 30, 2009 and 2010:


        
        
       Increase
      (Decrease)
         
        
       Increase
      (Decrease)
       

       Three Months Ended
      March 31, 2009
       Three Months Ended
      March 31, 2010
        Six Months Ended
      June 30, 2009
       Six Months Ended
      June 30, 2010
       
      Segment Tons % *  Tons % * 

       (in millions, except %)
        (in millions, except %)
       

      Central Appalachia

       1.3 0.4 (0.9) (69.2)% 2.4 1.0 (1.4) (59.9)%

      Northern Appalachia

       0.6 0.5 (0.1) (11.8)% 1.1 1.0 (0.1) (14.5)%

      Other

       0.1 0.1  (28.4)% 0.1 0.1  (26.0)%
                        

      Total *†

       2.0 0.9 (1.1) (51.1)% 3.7 2.0 (1.7) (44.7)%
                        

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

              We sold 0.92.0 million tons of coal in the threesix months ended March 31,June 30, 2010 as compared to the 2.03.7 million tons sold in the threesix months ended March 31,June 30, 2009. This decrease in tons sold was primarily due to lower demand for coal in our Central Appalachia segment. Tons of coal sold in this segment decreased by 0.91.4 million, or 69.2%59.9%, to 0.41.0 million tons for the threesix months ended March 31,June 30, 2010 from 1.32.4 million tons for the threesix months ended March 31,June 30, 2009. For our Northern Appalachia segment, tons of coal sold decreased from 0.61.1 million tons for the threesix months ended March 31,June 30, 2009 to 0.51.0 million tons for the threesix months ended March 31,June 30, 2010. This decrease was also the result of a decrease in demand for coal in our Northern Appalachiathe segment. SalesCoal sales from our Other segment remained relatively steady at 0.1 milliondecreased from approximately 148,000 tons for the threesix months ended March 31,June 30, 2009 and 2010.to approximately 110,000 tons for the six months ended June 30, 2010, also due to decreased demand.

              Revenues. The following table presents revenues and coal revenues per ton by reportable segment for the threesix months ended March 31,June 30, 2009 and 2010:



        
        
       Increase
      (Decrease)
       
        
        
       Increase
      (Decrease)
       


       Three Months Ended
      March 31, 2009
       Three Months Ended
      March 31, 2010
       
       Six Months Ended
      June 30, 2009
       Six Months Ended
      June 30, 2010
       
      SegmentSegment $ % * Segment $ % * 


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

      Central Appalachia

      Central Appalachia

       

      Central Appalachia

       

      Coal revenues

       $85.0 $38.5 $(46.5) (54.7)%

      Coal revenues

       $162.3 $89.9 $(72.4) (44.6)%

      Freight and handling revenues

           

      Freight and handling revenues

           

      Other revenues

       0.2 0.1 (0.1) (61.4)%

      Other revenues

       0.4 0.4  (3.7)%
                         

      Total revenues

       $85.2 $38.6 $(46.6) (54.7)%

      Total revenues

       $162.7 $90.3 $(72.4) (44.5)%
                         

      Coal revenues per ton *

       65.19 95.80 30.62 47.0%

      Coal revenues per ton *

       $66.96 $92.44 $25.48 38.1%

      Northern Appalachia

      Northern Appalachia

       

      Northern Appalachia

       

      Coal revenues

       $24.8 $21.7 $(3.1) (12.5)%

      Coal revenues

       $49.6 $42.1 $(7.5) (15.2)%

      Freight and handling revenues

       1.2 0.9 (0.3) (21.1)%

      Freight and handling revenues

       2.5 1.9 (0.6) (22.1)%

      Other revenues

       1.5 1.4 (0.1) (7.1)%

      Other revenues

       3.0 2.7 (0.3) (10.7)%
                         

      Total revenues

       $27.5 $24.0 $(3.5) (12.6)%

      Total revenues

       $55.1 $46.7 $(8.4) (15.3)%
                         

      Coal revenues per ton *

       44.50 44.14 (0.35) (0.8)%

      Coal revenues per ton *

       $44.20 $43.83 $(0.37) (0.8)%

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       Increase
      (Decrease)
       
        
        
       Increase
      (Decrease)
       


       Three Months Ended
      March 31, 2009
       Three Months Ended
      March 31, 2010
       
       Six Months Ended
      June 30, 2009
       Six Months Ended
      June 30, 2010
       
      SegmentSegment $ % * Segment $ % * 


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

      Other

      Other

       

      Other

       

      Coal revenues

       $3.3 $2.4 $(0.9) (26.5)%

      Coal revenues

       $6.3 $4.8 $(1.5) (23.8)%

      Freight and handling revenues

           

      Freight and handling revenues

           

      Other revenues

       0.7 1.6 0.9 130.9%

      Other revenues

       1.9 3.3 1.4 69.8%
                         

      Total revenues

       $4.0 $4.0 $   

      Total revenues

       $8.2 $8.1 $(0.1) (1.8)%
                         

      Coal revenues per ton *

       42.54 43.68 1.14 2.7%

      Coal revenues per ton *

       $42.43 $43.67 $1.23 2.9%

      Total

      Total

       

      Total

       

      Coal revenues

       $113.1 $62.6 $(50.5)$(44.6)%

      Coal revenues

       $218.3 $136.7 $(81.4) (37.4)%

      Freight and handling revenues

       1.2 0.9 (0.3) (21.1)%

      Freight and handling revenues

       2.5 1.9 (0.6) (22.1)%

      Other revenues

       2.4 3.1 0.7 26.8%

      Other revenues

       5.3 6.4 1.1 9.2%
                         

      Total revenues

       $116.7 $66.6 $(50.1) (42.9)%

      Total revenues

       $226.1 $145.0 $(81.1) (35.9)%
                         

      Coal revenues per ton *

       58.33 65.98 7.66 13.1%

      Coal revenues per ton *

       $59.06 $66.96 $7.90 13.4%

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

              Our total revenues for the threesix months ended March 31,June 30, 2010 decreased by $50.1$81.1 million, or 42.9%35.9%, to $66.6$145.0 million from $116.7$226.1 million for the threesix months ended March 31,June 30, 2009. The decline in total revenues was due to a decrease in demand for both steam and metallurgical coal. Coal revenues per ton were $65.98$66.96 for the quartersix months ended March 31,June 30, 2010, an increase of $7.66,$7.90, or 13.1%13.4%, from $58.33$59.06 per ton for the quartersix months ended March 31,June 30, 2009. This increase in coal revenues per ton was primarily the result of the sale of higher quality coal at a higher price per ton.

              For our Central Appalachia segment, coal revenues decreased by $46.5$72.4 million, or 54.7%44.6%, to $38.5$89.9 million for the threesix months ended March 31,June 30, 2010 from $85.0$162.3 million for the threesix months ended March 31,June 30, 2009 due to fewer tons of coal sold in the first six months of 2010. Coal revenues per ton for our Central Appalachia segment increased by $30.62,$25.48, or 47.0%38.1%, to $95.80$92.44 per ton for the threesix months ended March 31,June 30, 2010 as compared to $65.19$66.96 for the threesix months ended March 31,June 30, 2009, due to increased sales of metallurgical coal at a higher price per ton.

              For our Northern Appalachia segment, coal revenues were $21.7$42.1 million for the threesix months ended March 31,June 30, 2010, a decrease of $3.1$7.5 million, or 12.5%15.2%, from $24.8$49.6 million for the threesix months ended March 31,June 30, 2009, as a result of a decrease in demand. Coal revenues per ton for our Northern Appalachia segment decreased by $0.35,$0.37, or 0.8%, to $44.14$43.83 per ton for the threesix months ended March 31,June 30, 2010 as compared to $44.50$44.20 per ton for the threesix months ended March 31,June 30, 2009. This decrease was primarily due to variations in the amount of coal sold under existing coal supply contracts.

              For our Other segment, coal revenues decreased by $0.9$1.5 million, or 26.5%23.8%, to $2.4$4.8 million for the threesix months ended March 31,June 30, 2010 from $3.3$6.3 million for the threesix months ended March 31,June 30, 2009. Coal revenues per ton for our Other segment were $43.68$43.67 for the threesix months ended March 31,June 30, 2010, an increase of $1.14,$1.23, or 2.7%2.9%, from $42.54$42.43 for the threesix months ended March 31,June 30, 2009 as a result of escalation provisions includeddue to an increase in the selling price to our contracts.primary customer for coal produced from our McClane Canyon mine. Other revenues for our Other segment increased by $0.9$1.4 million for the threesix months ended March 31,June 30, 2010 from the threesix months ended March 31,June 30, 2009. This increase was


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      primarily due to a $0.6$0.9 million increase in sales revenue from our roof supportbolt manufacturing company and a $0.2$0.3 million increase in revenue from the provision of oilfield services.


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              Costs and Expenses. The following table presents costs and expenses (including the cost of purchased coal) and cost of operations per ton by reportable segment for the threesix months ended March 31,June 30, 2009 and 2010:


        
        
       Increase
      (Decrease)
         
        
       Increase
      (Decrease)
       

       Three Months Ended
      March 31, 2009
       Three Months Ended
      March 31, 2010
        Six Months Ended
      June 30, 2009
       Six Months Ended
      June 30, 2010
       
      Segment $ % *  $ % * 

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

      Central Appalachia

        

      Cost of operations (exclusive of depreciation, depletion and amortization shown separately below)

       $76.9 $24.6 $(52.3) (68.1)% $139.6 $60.9 $(78.7) (56.4)%

      Freight and handling costs

                

      Depreciation, depletion and amortization

       6.8 4.7 (2.1) (31.0)% 13.6 9.5 (4.1) (30.3)%

      Selling, general and administrative

       4.1 3.4 (0.7) (17.1)% 8.4 7.1 (1.3) (16.1)%

      Cost of operations per ton *

       $58.96 $61.09 $2.13 3.6% $57.59 $62.64 $5.05 8.8%

      Northern Appalachia

        

      Cost of operations (exclusive of depreciation, depletion and amortization shown separately below)

       $17.8 $17.1 $(0.7) (3.8)% $36.6 $33.1 $(3.5) (9.4)%

      Freight and handling costs

       0.9 0.6 (0.2) (28.2)% 2.0 1.4 (0.6) (26.9)%

      Depreciation, depletion and amortization

       2.1 1.9 (0.2) (8.0)% 4.0 4.0  (0.1)%

      Selling, general and administrative

       0.1 0.1  (19.2)% 0.2 0.2  (8.4)%

      Cost of operations per ton *

       $31.92 $34.82 $2.90 9.1% $32.59 $34.53 $1.94 6.0%

      Other

        

      Cost of operations (exclusive of depreciation, depletion and amortization shown separately below)

       $3.6 $4.7 $1.1 28.8% $7.3 $10.2 $2.9 39.0%

      Freight and handling costs

                

      Depreciation, depletion and amortization

       1.1 1.2 0.1 5.7% 2.3 2.3  2.7%

      Selling, general and administrative

       0.2 0.2  14.1% 0.4 0.4  (3.5)%

      Cost of operations per ton **

       n/a n/a n/a n/a  n/a n/a n/a n/a 

      Total

        

      Cost of operations (exclusive of depreciation, depletion and amortization shown separately below)

       $98.3 $46.4 (51.9) (52.9)% $183.5 $104.2 $(79.3) (43.2)%

      Freight and handling costs

       0.9 0.6 (0.3) (28.2)% 2.0 1.4 (0.6) (26.9)%

      Depreciation, depletion and amortization

       10.0 7.8 (2.2) (22.2)% 19.9 15.8 (4.1) (20.5)%

      Selling, general and administrative

       4.4 3.7 (0.7) (16.0)% 9.0 7.6 1.4 (15.4)%

      Cost of operations per ton *

       $50.69 $48.82 (1.87) (3.7)% $49.66 $51.02 $1.37 2.8%

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

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              Cost of Operations. Total cost of operations was $46.4$104.2 million for the threesix months ended March 31,June 30, 2010 as compared to $98.3$183.5 million for the threesix months ended March 31,June 30, 2009, primarily as a result of a 0.60.7 million ton decrease in the amount of coal produced for the quartersix months ended March 31,June 30, 2010 as compared to the same period in 2009. Our cost of operations per ton was $48.82$51.02 for the threesix months ended March 31,June 30, 2010, a decreasean increase of $1.87,$1.37, or 3.7%2.8%, from the threesix months ended March 31,June 30, 2009. This overall decreaseincrease in the cost of operations on a per ton basis was primarily due to the production of a higher percentage of our coalincreased "per ton" costs in our Central Appalachia and Northern Appalachia segmentsegments described below for the threesix months ended March 31,June 30, 2010 as compared to the threesix months ended March 31,June 30, 2009.

              Our cost of operations for the Central Appalachia segment decreased by $52.3$78.7 million, or 68.1%56.4%, to $24.6$60.9 million for the threesix months ended March 31,June 30, 2010 from $76.9$139.6 million for the threesix months ended March 31,June 30, 2009, primarily resulting from decreases in coal production. Our cost of operations per ton however increased to $61.09$62.64 per ton for the threesix months ended March 31,June 30, 2010 from $58.96$57.59 per ton for threesix months ended March 31,June 30, 2009. This increase in cost of operations per ton was primarily due to higher cost of labor, employee benefits and outside services, allocated across fewer tons of coal sold,taxes and insurance and royalty costs, offset by reductions in the cost of diesel fuel and repairs and maintenance.

              In our Northern Appalachia segment, our cost of operations decreased by $0.7$3.5 million, or 3.8%9.4%, to $17.1$33.1 million for the threesix months ended March 31,June 30, 2010 from $17.8$36.6 million for the threesix months ended March 31,June 30, 2009, primarily due to a decrease in the number of tons produced in the first quartersix months of 2010. Our cost of operations per ton increased to $34.82$34.53 for the threesix months ended March 31,June 30, 2010 from $31.92$32.59 for the threesix months ended March 31,June 30, 2009, an increase of $2.90$1.94 per ton, or 9.1%6.0%. This increase in cost of operations per ton was primarily due to higher costcosts of labor, employee benefitsoutside services and outside servicesmaintenance costs allocated across fewer tons of coal sold.

              In addition, we experienced an increase in roof support costs per ton due to difficult mining conditions. Cost of operations in our Other segment increased by $1.1$2.9 million for the threesix months ended March 31,June 30, 2010 as compared to the threesix months ended March 31,June 30, 2009. This increase was primarily due to additional reclamationoperating costs incurred by our ancillary service companies and development costs relating to new roof support products at our roof supportbolt manufacturing company.

              Freight and Handling. Total freight and handling cost for the threesix months ended March 31,June 30, 2010 decreased by $0.3$0.6 million, or 28.2%26.9%, to $0.6$1.4 million from $0.9$2.0 million for the threesix months ended March 31,June 30, 2009. This decrease was primarily due to a decrease of 1.01.7 million tons of coal sold for the threesix months ended March 31,June 30, 2010 as compared to the threesix months ended March 31,June 30, 2009.

              Depreciation, Depletion and Amortization. Total depreciation, depletion and amortization, or DD&A, expense for the threesix months ended March 31,June 30, 2010 was $7.8$15.8 million as compared to $10.0$19.9 million for the threesix months ended March 31,June 30, 2009.

              For the threesix months ended March 31,June 30, 2010, our depreciation cost was $6.6$13.4 million as compared to $7.4$15.5 million for the threesix months ended March 31,June 30, 2009. The decrease in depreciation cost in 2010 was primarily due to the disposal and idling of assets at certain less profitable surface mining operations.

              For the threesix months ended March 31,June 30, 2010, our depletion cost was $0.5$1.0 million as compared to $0.8$1.4 million for the threesix months ended March 31,June 30, 2009. The decrease in depletion cost in 20092010 was primarily a result of the decrease in the number of tons of coal produced for the threesix months ended March 31,June 30, 2010. Depletion is applied on a per ton basis as coal is produced and decreases as production decreases.

              For the three months ended March 31, 2010, our amortization cost was $0.7 million as compared to $1.7 million for the three months ended March 31, 2009. This decrease is primarily


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              For the six months ended June 30, 2010, our amortization cost was $1.4 million as compared to $3.0 million for the six months ended June 30, 2009. This decrease is primarily attributable to an overall decrease in production and a concurrent reduction in the allocationamortization of certain mine development and asset retirement costs based on the lower number of tons of coal produced.

              Selling, General and Administrative. SG&A expense for the threesix months ended March 31,June 30, 2010 was $3.7$7.6 million as compared to $4.4$9.0 million for the threesix months ended March 31,June 30, 2009. This decrease in SG&A expense was primarily due to a $0.6 million reduction in uncollectible accounts for the six months ended June 30, 2010 as compared to the six months ended June 30, 2009 and to our successful efforts to reduce administrative costs. These efforts resulted in a decrease in administrative labor costs of $0.5$0.3 million, a decrease in legal fees of $0.1 million and a decrease in professional fees and servicesrent of $0.2$0.1 million.

              Interest Expense. Interest expense for the threesix months ended March 31,June 30, 2010 was $1.5$2.8 million as compared to $1.2$2.9 million for the threesix months ended March 31,June 30, 2009, an increasea decrease of $0.3$0.1 million, or 25.7%.This increase3.8%. This decrease was primarily the result of an increasea reduction in the interest rate applicablebalance due under our credit facility, as amended on March 31, 2009.

              Income Tax Expense (Benefit). For the three months ended March 31, 2009 and 2010, we operated as a partnership and, as such, were not subject to federal income tax. For the three months ended March 31, 2009 and 2010, we did not operate in any state or local jurisdictions that imposed an income tax on partnerships.facility.

              Net Income (Loss). The following table presents net income (loss) by reportable segment for the threesix months ended March 31,June 30, 2009 and 2010:

      Segment Three Months Ended
      March 31, 2009
       Three Months Ended
      March 31, 2010
       Increase
      (Decrease)
        Six Months Ended
      June 30, 2009
       Six Months Ended
      June 30, 2010
       Increase
      (Decrease)
       

       (in millions)
        (in millions)
       

      Central Appalachia

       $(4.1)$4.7 $8.8  $(3.7)$10.2 $13.9 

      Northern Appalachia

       5.4 2.6 (2.8) 9.8 4.6 (5.2)

      Eastern Met *

        (0.1) (0.1) (0.3) 0.4 0.7 

      Other

       0.7 (0.6) (1.3) 1.6 (1.5) (3.1)
                    

      Total

       $2.0 $6.6 $4.6  $7.4 $13.7 $6.3 
                    

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

              For the threesix months ended March 31,June 30, 2010, total net income increased to $6.6$13.7 million from $2.0$7.4 million for the threesix months ended March 31,June 30, 2009. This increase was primarily due to the sale of higher quality coal and our successful cost containment efforts. For our Central Appalachia segment, net income increased to $4.7$10.2 million for the threesix months ended March 31,June 30, 2010, an improvement of $8.8$13.9 million as compared to the threesix months ended March 31,June 30, 2009, primarily due to the sale of higher quality coal and successful cost containment efforts. Net income in our Northern Appalachia segment decreased by $2.8$5.2 million to $2.6$4.6 million for the threesix months ended March 31,June 30, 2010, from $5.4$9.8 million for the threesix months ended March 31,June 30, 2009. This decrease was primarily the result of challenging geological conditions that limited production capacity and resulted in a decrease in tons of coal produced and an increase in operational costs such as roof support, labor and repairs on a per ton basis. Our Eastern Met segment recorded anet income of $0.4 million for the six months ended June 30, 2010, an increase of $0.7 million from the net loss of $0.1$0.3 million recorded for the threesix months ended March 31, 2010June 30, 2009. This increase occurred as a result of lower demand in January and February of 2010. This segment broke even for the three months ended March 31, 2009.joint venture became fully operational. For our Other segment, we had a net loss of $0.6$1.5 million for the threesix months ended March 31,June 30, 2010, a decrease of $3.1 million as compared to net income of $0.7$1.6 million recorded for the threesix months ended March 31, 2009June 30, 2009. This decrease was primarily due to a $1.1 million decrease in income from our McClane Canyon mine, a $0.2 million decrease in income from our roof bolt manufacturing company and a $1.8 million decrease in income from our ancillary service companies due to a decrease in trucking revenues as a result of the lower number of tons of coal sold.


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              EBITDA. The following table presents EBITDA by reportable segment for the threesix months ended March 31,June 30, 2009 and 2010:

      Segment Three Months Ended
      March 31, 2009
       Three Months Ended
      March 31, 2010
       Increase
      (Decrease)
        Six Months Ended
      June 30, 2009
       Six Months Ended
      June 30, 2010
       Increase
      (Decrease)
       

       (in millions)
        (in millions)
       

      Central Appalachia

       $3.5 $10.1 $6.6  $11.6 $20.9 $9.3 

      Northern Appalachia

       7.7 5.0 (2.7) 14.6 9.7 (4.9)

      Eastern Met *

        (0.1) (0.1) (0.3) 0.4 0.7 

      Other

       1.9 0.8 (1.1) 4.2 1.3 (2.9)
                    

      Total

       $13.1 $15.8 $2.6  $30.1 $32.3 $2.2 
                    

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

              Total EBITDA for the threesix months ended March 31,June 30, 2010 was $15.8$32.3 million, an increase of $2.6$2.2 million or 20.3%, from the threesix months ended March 31,June 30, 2009 primarily due to an increase in net income of $4.6$6.3 million offset by an increasea decrease in depreciation expense. Results of operations from our Eastern Met segment are recorded using the equity method and are reflected as a single line item in our financial statements. Therefore, depreciation, depletion and amortization and interest expense and income tax expense (benefit) are not presented separately for our Eastern Met segment. Please read "—Reconciliation of EBITDA to Net Income by Segment" for reconciliations of EBITDA to net income on a segment basis.

      Year Ended December 31, 2009 Compared to Year Ended December 31, 2008

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


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

       
        
        
       Increase
      (Decrease)
       
       
       Year Ended
      December 31, 2008
       Year Ended
      December 31, 2009
       
      Segment Tons % * 
       
       (in millions, except %)
       

      Central Appalachia

        5.5  4.2  (1.3) (22.0)%

      Northern Appalachia

        2.2  2.2    (2.7)%

      Other

        0.3  0.3    (5.3)%
                 

      Total †

        8.0  6.7  (1.3) (16.0)%
                 

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

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


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



        
        
       Increase
      (Decrease)
       
        
        
       Increase
      (Decrease)
       


       Year Ended
      December 31, 2008
       Year Ended
      December 31, 2009
       
       Year Ended
      December 31, 2008
       Year Ended
      December 31, 2009
       
      SegmentSegment $ % * Segment $ % * 


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

      Central Appalachia

      Central Appalachia

       

      Central Appalachia

       

      Coal revenues

       $310.6 $295.1 $(15.5) (5.0)%

      Coal revenues

       $310.6 $295.1 $(15.5) (5.0)%

      Freight and handling revenues

       
      0.8
       
       
      (0.8

      )
       
      (100.0

      )%

      Freight and handling revenues

       
      0.8
       
       
      (0.8

      )
       
      (100.0

      )%

      Other revenues

       
      5.1
       
      2.6
       
      (2.5

      )
       
      (49.1

      )%

      Other revenues

       
      5.1
       
      2.6
       
      (2.5

      )
       
      (49.1

      )%
                         

      Total revenues

       $316.5 $297.7 $(18.8) (5.9)%

      Total revenues

       $316.5 $297.7 $(18.8) (5.9)%
                         

      Coal revenues per ton *

       $56.74 $69.10 $12.36 21.8%

      Coal revenues per ton *

       $56.74 $69.10 $12.36 21.8%

      Northern Appalachia

      Northern Appalachia

       

      Northern Appalachia

       

      Coal revenues

       $89.9 $95.5 $5.6 6.1%

      Coal revenues

       $89.9 $95.5 $5.6 6.1%

      Freight and handling revenues

       
      7.1
       
      5.0
       
      (2.1

      )
       
      (29.3

      )%

      Freight and handling revenues

       
      7.1
       
      5.0
       
      (2.1

      )
       
      (29.3

      )%

      Other revenues

       
      11.4
       
      6.2
       
      (5.2

      )
       
      (45.0

      )%

      Other revenues

       
      11.4
       
      6.2
       
      (5.2

      )
       
      (45.0

      )%
                         

      Total revenues

       $108.4 $106.7 $(1.7) (1.6)%

      Total revenues

       $108.4 $106.7 $(1.7) (1.6)%
                         

      Coal revenues per ton *

       $40.44 $44.12 $3.68 9.1%

      Coal revenues per ton *

       $40.44 $44.12 $3.68 9.1%

      Other

       

      Coal revenues

       $8.3 $11.2 $2.9 34.9%

      Freight and handling revenues

       
      2.3
       
       
      (2.3

      )
       
      (100.0

      )%

      Other revenues

       
      3.4
       
      4.2
       
      0.8
       
      20.8

      %
               

      Total revenues

       $14.0 $15.4 $1.4 9.2%
               

      Coal revenues per ton *

       $29.74 $42.35 $12.61 42.4%

      Total

       

      Coal revenues

       $408.8 $401.8 $(7.0) (1.7)%

      Freight and handling revenues

       
      10.2
       
      5.0
       
      (5.2

      )
       
      (50.5

      )%

      Other revenues

       
      19.9
       
      13.0
       
      (6.9

      )
       
      (34.8

      )%
               

      Total revenues

       $438.9 $419.8 $(19.1) (4.4)%
               

      Coal revenues per ton *

       $51.25 $59.98 $8.73 17.0%

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       Increase
      (Decrease)
       
       
       Year Ended
      December 31, 2008
       Year Ended
      December 31, 2009
       
      Segment $ % * 
       
       (in millions, except per ton data and %)
       

      Other

                   
       

      Coal revenues

       $8.3 $11.2 $2.9  34.9%
       

      Freight and handling revenues

        
      2.3
        
        
      (2.3

      )
       
      (100.0

      )%
       

      Other revenues

        
      3.4
        
      4.2
        
      0.8
        
      20.8

      %
                 
       

      Total revenues

       $14.0 $15.4 $1.4  9.2%
                 
       

      Coal revenues per ton *

       $29.74 $42.35 $12.61  42.4%

      Total

                   
       

      Coal revenues

       $408.8 $401.8 $(7.0) (1.7)%
       

      Freight and handling revenues

        
      10.2
        
      5.0
        
      (5.2

      )
       
      (50.5

      )%
       

      Other revenues

        
      19.9
        
      13.0
        
      (6.9

      )
       
      (34.8

      )%
                 
       

      Total revenues

       $438.9 $419.8 $(19.1) (4.4)%
                 
       

      Coal revenues per ton *

       $51.25 $59.98 $8.73  17.0%

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

              Our total revenues for the year ended December 31, 2009 decreased by $19.1 million, or 4.4%, to $419.8 million from $438.9 million for the year ended December 31, 2008. The decline in total revenues was due to a decrease in coal demand as a result of the global recession. Please read "The Coal Industry." Coal revenues per ton were $59.98 for the year ended 2009, an increase of $8.73, or 17.0%, from $51.25 per ton for the year ended December 31, 2008. This increase in coal revenues per ton for the year ended December 31, 2009 was primarily the result of supply contracts executed in 2008 at favorable prices offset by the sale of a smaller percentage of metallurgical coal. The impact of the favorable prices included in these contracts was an increase in coal revenue per ton of approximately $11.49. This increase was offset by the impact of a less favorable sales mix as compared to the year ended December 31, 2008. This impact was a decrease of approximately $2.76 per ton.


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

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

              For our Other segment, coal revenues increased by $2.9 million, or 34.9%, to $11.2 million for the year ended December 31, 2009 from $8.3 million for the year ended December 31, 2008. Coal revenues per ton for our Other segment were $42.35 for the year ended December 31, 2009,


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      an increase of $12.61, or 42.4%, from $29.74 for the year ended December 31, 2008 as a result of favorable prices included in supply contracts executed in 2008.

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

       
        
        
       Increase
      (Decrease)
       
       
       Year Ended
      December 31, 2008
       Year Ended
      December 31, 2009
       
      Segment $ % * 
       
       (in millions, except per ton data and %)
       

      Central Appalachia

                   

      Cost of operations (exclusive of depreciation, depletion and amortization shown separately below)

       $272.8 $249.1 $(23.7) (8.7)%

      Freight and handling costs

        0.7    (0.7) (100.0)%

      Depreciation, depletion and amortization

        24.9  23.9  (1.0) (4.1)%

      Selling, general and administrative

        14.4  15.5  1.1  7.6%

      Cost of operations per ton *

       $49.84 $58.32 $8.48  17.0%

      Northern Appalachia

                   

      Cost of operations (exclusive of depreciation, depletion and amortization shown separately below)

       $76.6 $71.5 $(5.1) (6.7)%

      Freight and handling costs

        7.2  4.0  (3.2) (44.7)%

      Depreciation, depletion and amortization

        8.1  7.8  (0.3) (2.8)%

      Selling, general and administrative

        0.4  0.4    10.9%

      Cost of operations per ton *

       $34.45 $33.04 $(1.40) (4.1)%

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       Increase
      (Decrease)
         
        
       Increase
      (Decrease)
       

       Year Ended
      December 31, 2008
       Year Ended
      December 31, 2009
        Year Ended
      December 31, 2008
       Year Ended
      December 31, 2009
       
      Segment $ % *  $ % * 

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

      Central Appalachia

       

      Cost of operations (exclusive of depreciation, depletion and amortization shown separately below)

       $272.8 $249.1 $(23.7) (8.7)%

      Freight and handling costs

       0.7  (0.7) (100.0)%

      Depreciation, depletion and amortization

       24.9 23.9 (1.0) (4.1)%

      Selling, general and administrative

       14.4 15.5 1.1 7.6%

      Cost of operations per ton *

       $49.84 $58.32 $8.48 17.0%

      Northern Appalachia

       

      Cost of operations (exclusive of depreciation, depletion and amortization shown separately below)

       $76.6 $71.5 $(5.1) (6.7)%

      Freight and handling costs

       7.2 4.0 (3.2) (44.7)%

      Depreciation, depletion and amortization

       8.1 7.8 (0.3) (2.8)%

      Selling, general and administrative

       0.4 0.4  10.9%

      Cost of operations per ton *

       $34.45 $33.04 $(1.40) (4.1)%

      Other

        

      Cost of operations (exclusive of depreciation, depletion and amortization shown separately below)

       $15.5 $15.8 $0.3 1.9% $15.5 $15.8 $0.3 1.9%

      Freight and handling costs

       2.3  (2.3) (100.0)% 2.3  (2.3) (100.0)%

      Depreciation, depletion and amortization

       3.4 4.5 1.1 32.1% 3.4 4.5 1.1 32.1%

      Selling, general and administrative

       4.3 0.9 (3.4) (79.8)% 4.3 0.9 (3.4) (79.8)%

      Cost of operations per ton **

       n/a n/a n/a n/a  n/a n/a n/a n/a 

      Total

        

      Cost of operations (exclusive of depreciation, depletion and amortization shown separately below)

       $364.9 $336.4 $(28.5) (7.8)% $364.9 $336.4 $(28.5) (7.8)%

      Freight and handling costs

       10.2 4.0 (6.2) (61.0)% 10.2 4.0 (6.2) (61.0)%

      Depreciation, depletion and amortization

       36.4 36.3 (0.2) (0.4)% 36.4 36.3 (0.2) (0.4)%

      Selling, general and administrative

       19.1 16.8 (2.3) (12.0)% 19.1 16.8 (2.3) (12.0)%

      Cost of operations per ton *

       $45.75 $50.21 $4.46 9.8% $45.75 $50.21 $4.46 9.8%

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

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              Cost of Operations. Total cost of operations was $336.4 million for the year ended December 31, 2009 as compared to $364.9 million for the year ended December 31, 2008, primarily resulting from a decrease in the amount of coal produced of 2.8 million tons for the year ended December 31, 2009 as compared to the same period in 2008; however, we sold 2.0 million tons of purchased coal for the year ended December 31, 2009, an increase of 1.5 million tons from the year ended December 31, 2008. Our cost of operations per ton was $50.21 for the year ended December 31, 2009, an increase of $4.46, or 9.8%, from the year ended December 31, 2008. This increase was primarily due to the higher costs of labor, insurance and purchased coal, partially offset by reductions in the cost of operating supplies such as diesel fuel and explosives. We took steps to reduce our workforce as production slowed but necessarily retained a higher percentage of employees in critical ancillary and support positions. These labor costs, when applied to the smaller base of tons produced, resulted in higher costs on a per ton basis.

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


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

              Cost of operations in our Other segment increased by $0.3 million for the year ended December 31, 2009 as compared to the year ended December 31, 2008.

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

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

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

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


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

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

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

              Income Tax Expense (Benefit). For the years ended December 31, 2008 and 2009, we operated as a partnership and, as such, were not subject to federal income tax. For the years ended December 31, 2008 and 2009, we did not operate in any state or local jurisdictions that imposed an income tax on partnerships.


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

      Segment Year Ended
      December 31, 2008
       Year Ended
      December 31, 2009
       Increase
      (Decrease)
       
       
       (in millions)
       

      Central Appalachia

       $(3.5)$0.6 $4.1 

      Northern Appalachia

        10.9  17.6  6.7 

      Eastern Met *

        (1.6) 0.9  2.5 

      Other

        (4.9) 0.4  5.3 
              

      Total

       $0.9 $19.5 $18.6 
              

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

              For the year ended December 31, 2009, total net income increased to $19.5 million from $0.9 million for the year ended December 31, 2008. This increase was due to favorable prices included in supply contracts executed in 2008 and successful cost containment efforts. For our Central Appalachia segment, net income increased to $0.6 million for the year ended December 31, 2009, an improvement of $4.1 million primarily due to higher coal revenues per ton as a result of favorable contract pricing, successful cost containment efforts. Net income in our Northern Appalachia segment increased by $6.7 million to $17.6 million for the year ended December 31, 2009, from $10.9 million for the year ended December 31, 2008 primarily due to higher coal revenues per ton resulting from favorable pricing included in contracts executed during 2008 for coal sold during 2009. Net income from our Eastern Met segment increased by $2.5 million for the year ended December 31, 2009, as compared to the year ended December 31, 2008, as a result of the Rhino Eastern mining complex reaching full production and beginning sales of metallurgical coal. For our Other segment, net income was $0.4 million for the year ended December 31, 2009 as compared to a net loss of $4.9 million for the year ended December 31, 2008, this increase was primarily due to abandoned public offering costs recorded in 2008, higher revenues from our Colorado operations and lower costs of operations from our ancillary businesses. These ancillary businesses provide services such as reclamation, maintenance and transportation.


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

      Segment Year Ended
      December 31, 2008
       Year Ended
      December 31, 2009
       Increase
      (Decrease)
       
       
       (in millions)
       

      Central Appalachia

       $24.9 $28.0 $3.1 

      Northern Appalachia

        20.4  27.3  6.9 

      Eastern Met *

        (1.6) 0.9  2.5 

      Other

        (0.8) 5.8  6.6 
              

      Total

       $42.9 $62.0 $19.1 
              

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

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

      Year Ended December 31, 2008 Compared to Year Ended December 31, 2007

              Summary. We sold 8.0 million tons of coal for the year ended December 31, 2008 as compared to 8.2 million tons of coal for the year ended December 31, 2007. Our coal revenues were $408.8 million for the year ended December 31, 2008 as compared to $394.1 million for the year ended December 31, 2007. The $14.7 million, or 3.7%, increase in coal revenues for the year ended December 31, 2008 was primarily due to a $2.95 per ton, or 6.1%, increase in coal revenue per ton. Net income for the year ended December 31, 2008 was $0.9 million as compared to $30.7 million for the year ended December 31, 2007. EBITDA was $42.9 million for the year ended December 31, 2008 as compared to $66.9 million for the year ended December 31, 2007. The decrease in net income and EBITDA for the year ended December 31, 2008 was primarily due to increases in labor costs and operating costs as a result of escalating fuel prices.

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

       
        
        
       Increase
      (Decrease)
       
       
       Year Ended
      December 31, 2007
       Year Ended
      December 31, 2008
       
      Segment Tons % * 
       
       (in millions, except %)
       

      Central Appalachia

        6.6  5.5  (1.1) (16.9)%

      Northern Appalachia

        1.3  2.2  0.9  67.8%

      Other

        0.3  0.3    14.5%
                 

      Total †

        8.2  8.0  (0.2) (2.4)%
                 

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

      Excludes tons sold by the joint venture, which owns the Rhino Eastern mining complex located in West Virginia and for which we serve as manager.

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              We sold 8.0 million tons of coal for the year ended December 31, 2008 as compared to 8.2 million tons of coal for the year ended December 31, 2007. We produced 7.7 million tons of coal and purchased 0.3 million tons of coal for the year ended December 31, 2008 as compared to producing 7.1 million tons of coal, purchasing 1.0 million tons of coal and selling 0.1 million tons of coal from inventory for the year ended December 31, 2007. Tons of coal sold in our Central Appalachia segment was 5.5 million tons for the year ended December 31, 2008, which included the sale of 0.3 million tons of purchased coal as compared to 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 inventory. For our Northern Appalachia segment, we sold 2.2 million tons of coal for the year ended December 31, 2008 as compared to 1.3 million tons for the year ended December 31, 2007. This was primarily a result of the addition of production capacity through the acquisition of our Sands Hill mining complex in December 2007. This operation sold 0.7 million tons of coal for year ended December 31, 2008. Sales of coal for our Other segment were flat at 0.3 million tons for the year ended December 31, 2008. All sales of coal in our Other segment were to a small customer base under supply contracts.

              Revenues. The following table presents revenue data by reportable segment for the year ended December 31, 2008 and 2007:

       
        
        
       Increase
      (Decrease)
       
       
       Year Ended
      December 31, 2007
       Year Ended
      December 31, 2008
       
      Segment Dollars % * 
       
       (in millions, except per ton data and %)
       

      Central Appalachia

                   

      Coal revenues

       $337.4 $310.6 $(26.8) (7.9)%

      Freight and handling revenues

        1.1  0.8  (0.3) (34.9)%

      Other revenues

        1.5  5.1  3.6  233.8%
                 

      Total revenues

       $340.0 $316.5 $(23.5) (6.9)%
                 

      Coal revenues per ton *

       $51.19 $56.74 $5.54  10.8%

      Northern Appalachia

                   

      Coal revenues

       $49.5 $89.9 $40.4  81.7%

      Freight and handling revenues

        1.4  7.1  5.7  424.3%

      Other revenues

        3.6  11.4  7.8  220.0%
                 

      Total revenues

       $54.5 $108.4 $53.9  99.3%
                 

      Coal revenues per ton *

       $37.35 $40.44 $3.09  8.3%

      Other

                   

      Coal revenues

       $7.2 $8.3 $1.1  15.1%

      Freight and handling revenues

        1.6  2.3  0.7  48.7%

      Other revenues

        0.2  3.4  3.2  1382.0%
                 

      Total revenues

       $9.0 $14.0 $5.0  55.9%
                 

      Coal revenues per ton *

       $29.60 $29.74 $0.14  0.5%

      Total

                   

      Coal revenues

       $394.1 $408.8 $14.7  3.7%

      Freight and handling revenues

        4.1  10.2  6.1  151.5%

      Other revenues

        5.3  19.9  14.6  274.3%
                 

      Total revenues

       $403.5 $438.9 $35.4  8.8%
                 

      Coal revenues per ton *

       $48.30 $51.25 $2.95  6.1%

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

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              Our total revenues for the year ended December 31, 2008 were $438.9 million as compared to $403.5 million for the year ended December 31, 2007. Our coal revenues were $408.8 million for the year ended December 31, 2008 as compared to $394.1 million for the year ended December 31, 2007, primarily due to a more favorable sales mix of steam and metallurgical coal, additional coal sales from our Sands Hill mining complex (acquired in December 2007). Coal revenues per ton increased by $2.95 per ton, or 6.1%, to $51.25 per ton for the year ended December 31, 2008 from $48.30 per ton for the year ended December 31, 2007. Increases in total coal revenue and coal revenue per ton were the result of a favorable sales mix of steam and metallurgical coal, growing demand for coal and a concurrent upward trend in prices.

              For our Central Appalachia segment, coal revenues decreased by $26.8 million, or 7.9%, to $310.6 million for the year ended December 31, 2008 from $337.4 million for the year ended December 31, 2007 due to fewer tons of coal sold for that segment partially offset by an increase in coal revenue per ton for the year ended December 31, 2008. Coal revenues per ton for our Central Appalachia segment increased by $5.54 per ton, or 10.8%, to $56.74 per ton for the year ended December 31, 2008 as compared to $51.19 for the year ended December 31, 2007. The increase in coal revenue per ton in our Central Appalachia segment in 2008 as compared to 2007 was the result of a favorable sales mix of steam and metallurgical coal and an upward trend in prices.

              For our Northern Appalachia segment, coal revenues were $89.9 million for the year ended December 31, 2008, an increase of $40.4 million, or 81.7%, from $49.5 million for the year ended December 31, 2007. The increase in coal revenues for the year ended December 31, 2008 in our Northern Appalachia segment was primarily due to an increase in tons of coal sold, as a result of the acquisition of the Sands Hill mining complex in December 2007 and an increase in coal revenue per ton. The Sands Hill mining complex sold 0.7 million tons of coal, generating $28.4 million in revenue for the year ended December 31, 2008 as compared to 0.02 million tons of coal sold generating $0.7 million in revenue for the year ended December 31, 2007. Coal revenues per ton for our Northern Appalachia segment increased by $3.09 per ton, or 8.3%, to $40.44 per ton for the year ended December 31, 2008 from $37.35 per ton for the year ended December 31, 2007. The increase in coal revenue per ton in 2008 as compared to 2007 was the result of growing demand for coal and a concurrent upward trend in prices.

              For our Other segment, coal revenues increased by $1.1 million, or 15.1%, to $8.3 million for the year ended December 31, 2008 from $7.2 million for the year ended December 31, 2007 due to an increase in the number of tons of coal sold and an increase in coal revenue per ton. Coal revenues per ton for our Other segment were $29.74 for the year ended December 31, 2008, an increase of $0.14, or 0.5%, from $29.60 for the year ended December 31, 2007. The increase in 2008 as compared to 2007 was primarily due to contract provisions that allowed us to recover a portion of higher fuel costs through increases in the sales prices charged by our McClane Canyon mining complex.


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              Costs and Expenses. The following table presents costs and expenses (including the cost of purchased coal), cost of operations per ton and cost of operations per ton produced by reportable segment for the years ended December 31, 2008 and 2007:

       
        
        
       Increase
      (Decrease)
       
       
       Year Ended
      December 31, 2007
       Year Ended
      December 31, 2008
       
      Segment Dollars % * 
       
       (in millions, except per ton data and %)
       

      Central Appalachia

                   

      Cost of operations (exclusive of depreciation, depletion and amortization shown separately below)

       $270.4 $272.8 $2.4  0.9%

      Freight and handling costs

        1.1  0.7  (0.4) (35.3)%

      Depreciation, depletion and amortization

        24.5  24.9  0.4  (1.7)%

      Selling, general and administrative

        13.2  14.4  1.2  9.0%

      Cost of operations per ton *

       $41.03 $49.84 $8.81  21.5%

      Northern Appalachia

                   

      Cost of operations (exclusive of depreciation, depletion and amortization shown separately below)

       $36.7 $76.6 $39.9  108.6%

      Freight and handling costs

        1.3  7.2  5.9  463.8%

      Depreciation, depletion and amortization

        4.3  8.1  3.8  88.5%

      Selling, general and administrative

        1.2  0.4  (0.8) (69.4)%

      Cost of operations per ton *

       $27.70 $34.45 $6.75  24.4%

      Other

                   

      Cost of operations (exclusive of depreciation, depletion and amortization shown separately below)

       $11.3 $15.5 $4.2  36.9%

      Freight and handling costs

        1.6  2.3  0.7  42.2%

      Depreciation, depletion and amortization

        1.9  3.4  1.5  74.2%

      Selling, general and administrative

        1.0  4.3  3.3  337.3%

      Cost of operations per ton **

        n/a  n/a  n/a  n/a 

      Total

                   

      Cost of operations (exclusive of depreciation, depletion and amortization shown separately below)

       $318.4 $364.9 $46.5  14.6%

      Freight and handling costs

        4.0  10.2  6.2  154.2%

      Depreciation, depletion and amortization

        30.7  36.4  5.7  18.5%

      Selling, general and administrative

        15.4  19.1  3.7  23.9%

      Cost of operations per ton *

       $39.02 $45.75 $6.72  17.2%

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

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              Cost of Operations. Total cost of operations was $364.9 million for the year ended December 31, 2008 as compared to $318.4 million for the year ended December 31, 2007, with the increase resulting primarily from an increase in coal produced of 0.7 million tons for the year ended December 31, 2008. Our cost of operations per ton increased by $6.72 per ton, or 17.2%, to $45.75 per ton for the year ended December 31, 2008 compared to $39.02 per ton for the year ended December 31, 2007. The increase in 2008 over 2007 primarily reflected increasing costs for labor, the direct effect of increased costs of fuel and the indirect effect of those fuel cost increases as reflected in fuel surcharges and increased transportation costs affecting the price of raw materials and supplies.

              Our cost of operations for our Central Appalachia segment increased by $2.4 million, or 0.9%, to $272.8 million for the year ended December 31, 2008 from $270.4 million for the year ended December 31, 2007. Our cost of operations per ton also increased by $8.81 per ton, or 21.5%, to $49.84 per ton for the year ended December 31, 2008 from $41.03 per ton for the year ended December 31, 2007. The increase in 2008 as compared to 2007 was due to increases in labor costs as a result of high demand for skilled workers, an overall increase in the cost of material and supplies as a result of escalating fuel costs and additional costs incurred as a result of poor geological conditions encountered in the coal production process.

              In our Northern Appalachia segment, our cost of operations increased by $39.9 million, or 108.6%, to $76.6 million for the year ended December 31, 2008 from $36.7 million for the year ended December 31, 2007. The increase in 2008 over 2007 was primarily due to our acquisition of the Sands Hill mining complex in December 2007, which increased our total cost of operations by $33.0 million. For the year ended December 31, 2008, costs of operations in the Sands Hill mining complex was $33.8 million as compared to $0.8 million for the year ended December 31, 2007. Also contributing to this increase were increases in the cost of materials and supplies as a result of escalating fuel costs. Our cost of operations per ton also increased by $6.75 per ton, or 24.4%, to $34.45 per ton for the year ended December 31, 2008 from $27.70 per ton for the year ended December 31, 2007. The increase was primarily the direct result of increased costs of fuel and the indirect effect of those fuel cost increases as reflected in fuel surcharges and increased transportation costs affecting the price of raw materials and supplies.

              Cost of operations in our Other segment increased by $4.2 million, or 36.9%, to $15.5 million for the year ended December 31, 2008 from $11.3 million for the year ended December 31, 2007. This increase was primarily due to increases in costs of operations in our ancillary businesses. These increases were primarily the result of the increasing price of fuel and the increased cost of labor.

              Freight and Handling. Total freight and handling costs for the year ended December 31, 2008 increased by $6.2 million, or 154.2%, to $10.2 million from $4.0 million for the year ended December 31, 2007. This increase was primarily due to additional production as a result of the addition of our Sands Hill mining complex in our Northern Appalachia segment and escalating fuel costs.

              Depreciation, Depletion and Amortization. Total DD&A expense for the year ended December 31, 2008 was $36.4 million as compared to $30.7 million for the year ended December 31, 2007. The increase in DD&A expense in 2008 as compared to 2007 was the result of a $5.0 million increase in depreciation as well as a $0.4 million increase in depletion and a $0.3 million increase in amortization.

              For the year ended December 31, 2008, our depreciation cost was $26.0 million as compared to $21.0 million for the year ended December 31, 2007. The increase in depreciation cost for the


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      year ended December 31, 2008 was primarily due to the acquisition of the Sands Hill mining complex in December 2007, the Deane mining complex in February 2008 as well as significant additions of machinery and equipment at other existing operations.

              For the year ended December 31, 2008, our depletion cost was $4.0 million as compared to $3.6 million for the year ended December 31, 2007. The higher depletion cost in 2008 was primarily due to an increase in production relating to our Sands Hill mining complex and Deane mining complex.

              For the year ended December 31, 2008, our amortization cost was $6.4 million as compared to $6.1 million for the year ended December 31, 2007 resulting from an increase in both amortization of mine development and asset retirement costs for the year ended December 31, 2008.

              Selling, General and Administrative. SG&A expenses increased by $3.7 million for the year ended December 31, 2008 primarily due to costs related to an abandoned public offering recorded in August of 2008.

              Interest Expense. Interest expense for the year ended December 31, 2008 was $5.5 million as compared to $5.6 million for the year ended December 31, 2007. Our interest rates were lower in 2008 compared to the rates in 2007.

              Income Tax Expense (Benefit). We are taxed as a partnership, and, as such, are not subject to federal income tax. For the year ended December 31, 2008, we did not operate in any state or local jurisdictions that imposed an income tax on partnerships. As a result, there was no income tax expense or benefit for the year ended December 31, 2008 as compared to an income tax benefit of $0.1 million for the year ended December 31, 2007. We incurred an income tax expense of $0.1 million in 2006 as a result of the state of Kentucky instituting a law effective January 1, 2005 that required partnerships to pay state income taxes. This law was repealed effective January 1, 2007, which resulted in a reversal of that income tax expense and generated an income tax benefit of $0.1 million for the year ended December 31, 2007.

              Net Income (Loss). The following table presents net income (loss) by reportable segment for years ended December 31, 2007 and 2008:

      Segment Year Ended
      December 31, 2007
       Year Ended
      December 31, 2008
       Increase
      (Decrease)
       
       
       (in millions)
       

      Central Appalachia

       $23.8 $(3.5)$(27.3)

      Northern Appalachia

        8.9  10.9  2.0 

      Eastern Met *

        n/a  (1.6) (1.6)

      Other

        (2.0) (4.9) (2.9)
              

      Total

       $30.7 $0.9 $(29.8)
              

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

              For the year ended December 31, 2008, total net income decreased by $29.8 million to $0.9 million from $30.7 million for the year ended December 31, 2007. The decrease in 2008 as compared to 2007 was primarily due to increased labor costs, escalating fuel costs, abandoned public offering costs recorded in 2008 and increased operational costs related to poor geological


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      conditions at specific operations. For our Central Appalachia segment, net loss was $3.5 million for the year ended December 31, 2008, as compared to a net income of $23.8 million for the year ended December 31, 2007. This decline of $27.3 million in net income was due to increased labor costs and escalating fuel costs as well as increased costs as a result of poor geological conditions encountered in the course of coal production and partially offset by an increase in coal prices per ton. Net income in our Northern Appalachia segment increased by $2.0 million, or 23.2%, to $10.9 million for the year ended December 31, 2008, from $8.9 million for the year ended December 31, 2007 primarily due to additional production at our Sands Hill mining complex, acquired in August of 2007 and higher coal prices per ton of coal sold. We experienced a net loss of $1.6 million for our Eastern Met segment for the year ended December 31, 2008 as a result of the start-up costs associated with the Rhino Eastern mining complex, which began producing coal for sale in December 2008. For our Other segment, net loss increased by $2.9 million, or 147.6%, to $4.9 million for the year ended December 31, 2008 from a net loss of $2.0 million for the year ended December 31, 2007 primarily due to abandoned public offering costs recorded in 2008 offset by savings resulting from improvements in productivity at our McClane Canyon mining complex.

              EBITDA. The following table presents EBITDA by reportable segment for the years ended December 31, 2007 and 2008:

      Segment Year Ended
      December 31, 2007
       Year Ended
      December 31, 2008
       Increase
      (Decrease)
       
       
       (in millions)
       

      Central Appalachia

       $52.3 $24.9 $(27.4)

      Northern Appalachia

        13.9  20.4  6.5 

      Eastern Met *

        n/a  (1.6) (1.6)

      Other

        0.7  (0.8) (1.5)
              

      Total

       $66.9 $42.9 $(24.0)
              

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

              Total EBITDA for the year ended December 31, 2008 was $42.9 million, a decrease of $24.0 million from $66.9 million for the year ended December 31, 2007. The decrease from 2007 to 2008 is primarily a result of a $29.8 million decrease in net income offset by a $5.7 million increase in DD&A. Results of operations from our Eastern Met segment are recorded using the equity method and are reflected as a single line item in our financial statements. Therefore, depreciation, depletion and amortization, interest expense and income tax expense (benefit) are not presented separately for our Eastern Met segment. Please read "—Reconciliation of EBITDA to Net Income by Segment" for reconciliations of EBITDA to net income on a segment basis.

      Reconciliation of EBITDA to Net Income by Segment

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


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      Year Ended December 31, 2007 Central
      Appalachia
       Northern
      Appalachia
       Other Total 
       
       (in millions)
       

      Net income (loss)

       $23.8 $8.9 $(2.0)$30.7 

      Plus:

                   
       

      Depreciation, depletion and amortization

        24.5  4.3  1.9  30.7 
       

      Interest expense

        4.1  0.7  0.8  5.6 
       

      Income tax (benefit)

        (0.1)     (0.1)
                

      EBITDA†

       
      $

      52.3
       
      $

      13.9
       
      $

      0.7
       
      $

      66.9
       
                

       

      Year Ended December 31, 2008 Central
      Appalachia
       Northern
      Appalachia
       Eastern
      Met *
       Other Total 
       
       (in millions)
       

      Net income (loss)

       $(3.5)$10.9 $(1.6)$(4.9)$0.9 

      Plus:

                      
       

      Depreciation, depletion and amortization

        24.9  8.1    3.4  36.4 
       

      Interest expense

        3.6  1.4    0.6  5.5 
                  

      EBITDA†

       
      $

      24.9
       
      $

      20.4
       
      $

      (1.6

      )

      $

      (0.9

      )

      $

      42.9
       
                  

       

      Year Ended December 31, 2009 Central
      Appalachia
       Northern
      Appalachia
       Eastern
      Met *
       Other Total 
       
       (in millions)
       

      Net income (loss)

       $0.6 $17.6 $0.9 $0.4 $19.5 

      Plus:

                      
       

      Depreciation, depletion and amortization

        23.9  7.9    4.5  36.3 
       

      Interest expense

        3.5  1.8    0.9  6.2 
                  

      EBITDA

       
      $

      28.0
       
      $

      27.3
       
      $

      0.9
       
      $

      5.8
       
      $

      62.0
       
                  

       

      Three Months Ended March 31, 2009 Central
      Appalachia
       Northern
      Appalachia
       Eastern
      Met *
       Other Total 
      Six Months Ended June 30, 2009Six Months Ended June 30, 2009 Central
      Appalachia
       Northern
      Appalachia
       Eastern
      Met *
       Other Total 


       (in millions)
       
       (in millions)
       

      Net income (loss)

      Net income (loss)

       $(4.1)$5.4 $ $0.7 $2.0 

      Net income (loss)

       $(3.7)$9.8 $(0.3)$1.6 $7.4 

      Plus:

      Plus:

       

      Plus:

       

      Depreciation, depletion and amortization

       6.8 2.0  1.1 9.9 

      Depreciation, depletion and amortization

       13.6 4.0  2.3 19.9 

      Interest expense

       0.7 0.3  0.2 1.2 

      Interest expense

       1.7 0.8  0.4 2.9 
                             

      EBITDA†

      EBITDA†

       
      $

      3.5
       
      $

      7.7
       
      $

       
      $

      1.9
       
      $

      13.1
       

      EBITDA†

       
      $

      11.6
       
      $

      14.6
       
      $

      (0.3

      )

      $

      4.2
       
      $

      30.1
       
                             

       

      Three Months Ended March 31, 2010 Central
      Appalachia
       Northern
      Appalachia
       Eastern
      Met *
       Other Total 
      Six Months Ended June 30, 2010Six Months Ended June 30, 2010 Central
      Appalachia
       Northern
      Appalachia
       Eastern
      Met *
       Other Total 


       (in millions)
       
       (in millions)
       

      Net income (loss)

      Net income (loss)

       $4.7 $2.6 $(0.1)$(0.6)$6.6 

      Net income (loss)

       $10.2 $4.6 $0.4 $(1.5)$13.7 

      Plus:

      Plus:

       

      Plus:

       

      Depreciation, depletion and amortization

       4.7 1.9  1.1 7.7 

      Depreciation, depletion and amortization

       9.5 4.0  2.3 15.8 

      Interest expense

       0.6 0.6  0.3 1.5 

      Interest expense

       1.2 1.1  0.5 2.8 
                             

      EBITDA†

      EBITDA†

       
      $

      10.1
       
      $

      5.0
       
      $

      (0.1

      )

      $

      0.8
       
      $

      15.8
       

      EBITDA†

       
      $

      20.9
       
      $

      9.7
       
      $

      0.4
       
      $

      1.3
       
      $

      32.3
       
                             

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

      EBITDA is calculated based on actual amounts and not the rounded amounts presented in this table.

      Table of Contents

      Liquidity and Capital Resources

      Liquidity

              Our business is capital intensive and requires substantial capital expenditures for purchasing, upgrading and maintaining equipment used in developing and mining our reserves, as well as complying with applicable environmental and mine safety laws and regulations. Our principal liquidity requirements are to finance current operations, fund capital expenditures, including acquisitions from time to time, and service our debt. Following completion of this offering, we expect our sources of liquidity to include cash generated by our operations, borrowings under our credit agreement and issuances of equity and debt securities. Furthermore, following the completion of this offering, we will make a minimum quarterly distribution of $0.445 per unit per quarter, which equates to $11.3 million per quarter, or $45.0 million per year, based on the number of common and subordinated units and the general partner interest to be outstanding immediately after completion of this offering, to the extent we have sufficient cash from our operations after establishment of cash reserves and payment of fees and expenses, including payments to our general partner and its affiliates. We do not have a legal obligation to pay this distribution. Please read "Cash Distribution Policy and Restrictions on Distributions."

              The principal indicators of our liquidity are our cash on hand and availability under our credit agreement. As of March 31,June 30, 2010, our available liquidity was $61.9$76.9 million, including cash on hand of $0.3$0.2 million and $61.6$76.7 million available under our credit agreement.

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

      Cash Flows

              ThreeSix Months Ended March 31,June 30, 2010 Compared to ThreeSix Months Ended March 31,June 30, 2009. Net cash provided by operating activities was $4.6$24.9 million for the threesix months ended March 31,June 30, 2010 as compared to $3.3$20.2 million for the threesix months ended March 31,June 30, 2009. This increase in cash provided by operating activities was primarily the result of an increase in net earnings due to favorable sales prices and our successful efforts to reduce costs and a decrease in the use of net working capital related to accrued expenses and other payables.liabilities.

              Net cash used in investing activities was $6.5$11.6 million for the threesix months ended March 31,June 30, 2010 as compared to $11.7$19.4 million for the threesix months ended March 31,June 30, 2009. The decrease in cash used forin investing activities was primarily due to a reduction in our expenditures for plant and equipment.equipment acquisitions and a decrease in amounts loaned to the joint venture.

              Net cash provided byused for financing activities for the threesix months ended March 31,June 30, 2010 was $1.6$13.8 million, which primarily representsrepresented the net repayment of borrowings under our credit agreement. Net cash used for financing activities for the six months ended June 30, 2009 was $2.3 million, which primarily represented the repayment of a loan from Wexford offset by net borrowings under our revolving line of credit offset by repayments of other long-term debt. Net cash provided by financing activities for the three months ended March 31, 2009 was $7.0 million, which represents borrowing under our line of credit offset by repayments of other long-term debt.facility.

              Year Ended December 31, 2009 Compared to Year Ended December 31, 2008. Net cash provided by operating activities was $41.5 million for the year ended December 31, 2009 as compared to $57.2 million for the year ended December 31, 2008. This decrease in 2009 as compared to 2008 was primarily the result of increases in accounts receivable, decreases in accounts payable and asset retirement obligations offset by higher net income.

              For the year ended December 31, 2009, net cash used in investing activities was $27.3 million as compared to $106.6 million for the year ended December 31, 2008. The


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      decrease in cash used for investing activities in 2009 as compared to 2008 was primarily due to a reduction in our expenditures for mining equipment and coal properties.

              Net cash used by financing activities was $15.4 million for the year ended December 31, 2009 as compared to net cash provided by financing activities of $47.8 million for the year ended December 31, 2008. In 2009 as compared to 2008, we had sufficient cash provided by operations to finance a larger portion of our growth and relied less on financing activities. In 2009, we borrowed $27.7 million less than the year in 2008 and paid back an additional $35.4 million of the debt as compared to the year ended December 31, 2008.

              Year Ended December 31, 2008 Compared to the Year Ended December 31, 2007. Net cash provided by operating activities was $57.2 million for the year ended December 31, 2008 as compared to $52.5 million for the year ended December 31, 2007. The greater amount in 2008 was primarily due to an increase in cash provided from decreases in accounts receivable offset by a decrease in net income.

              Net cash used in investing activities for the year ended December 31, 2008 was $106.6 million as compared to $28.1 million in the year ended December 31, 2007. This increase was the result of additional investments in equipment, asset acquisitions and coal reserves in 2008 as compared to 2007.

              Net cash generated by financing activities was $47.8 million for the year ended December 31, 2008 as compared to net cash used in financing activities of $21.2 million for the year ended December 31, 2007. We made $25.0 million less in debt payments and borrowed $35.1 million more in cash in the year ended December 31, 2008 as compared to the year ended December 31, 2007 in order to finance acquisitions of additional operations and replacements of equipment.

      Contractual Obligations

              We have contractual obligations that are required to be settled in cash. The amount of our contractual obligations as of December 31, 2009 were as follows:

       
       Payments Due by Period 
       
       Total Less than
      1 Year
       1-3 Years 4-5 Years More than
      5 Years
       
       
       (in thousands)
       

      Long-term debt obligations (including interest) (1)

       $122,137 $2,242 $1,508 $114,822 $3,565 

      Asset retirement obligations

        45,101  5,428  10,000  10,000  19,673 

      Operating lease obligations (2)

        8,204  4,883  2,332  989   

      Diesel fuel obligations

        7,437  7,437       

      Ammonia nitrate obligations

        2,392  2,392       

      Advance royalties (3)

        38,444  4,207  7,764  7,563  18,910 

      Retiree medical obligations

        5,210  95  473  888  3,754 
                  
       

      Total

       $228,925 $26,684 $22,077 $134,262 $45,902 
                  

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

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      Capital Expenditures

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

              For the year ending December 31, 2010, we have budgeted $31.1$37.4 million in capital expenditures. We believe that we have sufficient liquid assets, cash flows from operations and borrowing capacity under our credit agreement to meet our financial commitments, debt service obligations, contingencies and anticipated capital expenditures. However, we are subject to business and operational risks that could adversely affect our cash flow. A material decrease in our cash flows would likely produce a corollary adverse effect on our borrowing capacity. From time to time, we may issue debt and equity securities.

      Off-Balance Sheet Arrangements

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

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

              As of March 31, 2009,June 30, 2010, we had $21.4$21.1 million in letters of credit outstanding, of which $18.5$18.2 million served as collateral for surety bonds.

      Credit Agreement

              Rhino Energy LLC, our wholly owned subsidiary, as borrower, and our operating subsidiaries, as guarantors, are parties to our $200.0 million credit agreement, which is available for general partnership purposes, including working capital and capital expenditures, and may be increased by up to $75.0 million with the consent of the lenders, so long as there is no event of default. Of the $200.0 million, $50.0 million is available for letters of credit. As of March 31,June 30, 2010, we had borrowings outstanding under our credit agreement of approximately


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      $117.0102.1 million and $21.4$21.1 million of letters of credit in place, leaving approximately $61.6$76.7 million of availability under our credit agreement. Upon application of the net proceeds from this offering and the related capital contribution from our general partner as described under "Use of Proceeds," we will have $50.1$34.5 million of indebtedness outstanding under our credit agreement. On June 30, 2010, in connection with this offering, we amended our credit agreement. References to our credit agreement refer to our credit agreement as amended.

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

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

              The credit agreement contains various covenants that may limit, among other things, our ability to:

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

              If an event of default exists under the credit agreement, the lenders are able to accelerate the maturity of the credit agreement and exercise other rights and remedies. The credit agreement prohibits us from making distributions if any potential default or event of default, as defined in


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      the credit agreement, occurs or would result from such distribution. Each of the following could be an event of default:

      Critical Accounting Policies and Estimates

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

      Company Environment and Risk Factors

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

      Investment in Joint Venture

              Investments in other entities are accounted for using the consolidation, equity method or cost basis depending upon the level of ownership, our ability to exercise significant influence over the operating and financial policies of the investee and whether we are determined to be the primary beneficiary. Equity investments are recorded at original cost and adjusted periodically to recognize our proportionate share of the investees' net income or losses after the date of investment. When net losses from an equity method investment exceed its carrying amount, the investment balance is reduced to zero and additional losses are not provided for. We


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      resume accounting for the investment under the equity method when the entity subsequently reports net income and our share of that net income exceeds the share of net losses not recognized during the period the equity method was suspended. Investments are written down only when there is clear evidence that a decline in value that is other than temporary has occurred.

              In May 2008, we entered into a joint venture, Rhino Eastern, with an affiliate of Patriot to acquire the Rhino Eastern mining complex. To initially capitalize the joint venture, we contributed approximately $16.1 million for a 51% ownership interest in the joint venture, and we account for the investment in the joint venture and its results of operations under the equity method. We consider the operations of this entity to comprise a reporting segment and have provided supplemental detail related to this operation in Note 15 to the Rhino Energy LLC unaudited historical condensed consolidated financial statements and Note 17 to the Rhino Energy LLC audited historical consolidated financial statements that are included elsewhere in this prospectus.

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

              As of March 31,June 30, 2010, December 31, 2009 and December 31, 2008, we have recorded our equity method investment of $17,056,473,$17,600,307, $17,186,362 and $16,293,489, respectively, as a long-term asset. Our maximum exposure to losses associated with our involvement in this variable interest entity would be limited to our equity investment of $17,056,473$17,600,307 as of March 31,June 30, 2010, plus any additional capital contributions, if required. We had not provided any additional contractually required support as of December 31, 2009; however, as disclosed in Note 12 to the Rhino Energy LLC audited historical consolidated financial statements that are included elsewhere in this prospectus, we had provided a loan in the amount of $377,183 to the joint venture.

      Concentrations of Credit Risk

              We do not require collateral or other security on accounts receivable. Credit risk is controlled through credit approvals and monitoring procedures. Please read Note 13 to the Rhino Energy LLC audited historical consolidated financial statements and Note 12 to the Rhino Energy LLC unaudited historical condensed consolidated financial statements included elsewhere in this prospectus for discussion of major customers.

      Property, Plant and Equipment

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


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      estimated proven and probable reserves. Gains or losses arising from sales or retirements are included in current operations.

              On March 30, 2005, the Financial Accounting Standards Board (FASB) ratified the consensus reached by the Emerging Issues Task Force, or EITF, on ASC Topic 930 (previously "EITF 04-06", "Accounting for Stripping Costs in the Mining Industry"). ASC Topic 930 applies to stripping costs incurred in the production phase of a mine for the removal of overburden or waste materials for the purpose of obtaining access to coal that will be extracted. Under the rule, stripping costs incurred during the production phase of the mine are variable production costs that are included in the cost of inventory produced and extracted during the period the stripping costs are incurred. The guidance in ASC Topic 930 consensus is effective for fiscal years beginning after December 15, 2005, with early adoption permitted. We have recorded stripping costs for all its surface mines incurred during the production phase as variable production costs that are included in the cost of inventory produced. We define a surface mine as a location where we utilize operating assets necessary to extract coal, with the geographic boundary determined by property control, permit boundaries, and/or economic threshold limits. Multiple pits that share common infrastructure and processing equipment may be located within a single surface mine boundary, which can cover separate coal seams that typically are recovered incrementally as the overburden depth increases. In accordance with ASC Topic 930, we define a mine in production as one from which saleable minerals have begun to be extracted (produced) from an ore body, regardless of the level of production; however, the production phase does not commence with the removal of de minimis saleable mineral material that occurs in conjunction with the removal of overburden or waste material for the purpose of obtaining access to an ore body. We capitalize only the development cost of the first pit at a mine site that may include multiple pits.

      Asset Impairments

              We follow ASC Topic 360 (previously Statement of Financial Accounting Standards, or SFAS, No. 144, "Accounting for the Impairment or Disposal of Long-Lived Assets"), which requires that projected future cash flows from use and disposition of assets be compared with the carrying amounts of those assets, when potential impairment is indicated. When the sum of projected undiscounted cash flows is less than the carrying amount, impairment losses are recognized. In determining such impairment losses, discounted cash flows are utilized to determine the fair value of the assets being evaluated. Also, in certain situations, expected mine lives are shortened because of changes to planned operations. When that occurs and it is determined that the mine's underlying costs are not recoverable in the future, reclamation and mine closing obligations are accelerated and the mine closing accrual is increased accordingly. To the extent it is determined that asset carrying values will not be recoverable during a shorter mine life, a provision for such impairment is recognized. There were no impairment losses recorded during the years ended December 31, 2009 and 2008.

      Asset Retirement Obligations

              ASC Topic 410 (previously SFAS No. 143, "Accounting for Asset Retirement Obligations") addresses asset retirement obligations that result from the acquisition, construction, or normal operation of long-lived assets. It requires companies to recognize asset retirement obligations at fair value when the liability is incurred or acquired. Upon initial recognition of a liability, an amount equal to the liability is capitalized as part of the related long-lived asset and allocated to expense over the useful life of the asset. We have recorded the asset retirement costs in coal properties.


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

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

              The adjustments to the liability from annual recosting reflect changes in expected timing, cash flow, and the discount rate used in the present value calculation of the liability. Changes in the asset retirement obligations for the year ended December 31, 2009 and the threesix months ended March 31,June 30, 2010 were calculated with the same discount rate (10%) used for the year ended December 31, 2008. Other recosting adjustments to the liability are made annually based on inflationary cost increases and changes in the expected operating periods of the mines.

      Workers' Compensation Benefits

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

      Revenue Recognition

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

              Coal sales revenues also result from the sale of brokered coal produced by others. The revenues related to brokered coal sales are included in coal sales revenues on a gross basis and the corresponding cost of the coal from the supplier is recorded in cost of coal sales in accordance with ASC Topic 605-45, "Principal Agent Considerations."

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


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

      Derivative Financial Instruments

              During the year ended December 31, 2008, we used futures contracts to manage the risk of fluctuations in the sales price of coal. We did not use derivative financial instruments for trading or speculative purposes. We recorded the derivative financial instruments as either assets or liabilities, at fair value, in accordance with ASC Topic 815, "Derivatives and Hedging." All futures contracts were settled as of December 31, 2008. We also use diesel fuel forward contracts to manage the risk of fluctuations in the cost of diesel fuel. Our diesel fuel forward contracts qualify for the normal purchase normal sale, or NPNS, exception prescribed by ASC Topic 815, based on management's intent and ability to take physical delivery of the diesel fuel.

      Income Taxes

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

      Recent Accounting Pronouncements

              Effective January 1, 2008, we adopted the new guidance codified in ASC Topic 820 (previously SFAS No. 157, "Fair Value Measures"), which clarifies the definition of fair value, establishes a framework for measuring fair value and expands the disclosures on fair value measurements. ASC Topic 820 applies whenever other statements require or permit assets or liabilities to be measured at fair value. ASC Topic 820 requirements for certain non-financial assets and liabilities were permitted to be deferred until the first quarter of 2009 in accordance with Financial Accounting Standards Board, or FASB, Staff Position 157-2,Effective Date of ASC Topic 820. We adopted this new guidance effective January 1, 2009, at the time of the adoption, there were no nonfinancial assets or nonfinancial liabilities that were measured at fair value on a nonrecurring basis. ASC Topic 820 establishes the following fair value hierarchy that prioritizes the inputs used to measure fair value:

              ASC Topic 805 (previously SFAS No. 141, "Business Combinations"), among other things, provides guidance for the way companies account for business combinations. This guidance requires transaction-related costs to be expensed as incurred, which were previously accounted for as a cost of acquisition. ASC Topic 805 also requires acquirers to estimate the acquisition-date fair value of any contingent consideration and recognize any subsequent


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      changes in the fair value of contingent consideration in earnings. In addition, restructuring costs the acquirer was not obligated to incur shall be recognized separately from the business acquisition. We adopted this guidance on a prospective basis as of January 1, 2009. The adoption of this guidance did not require remeasurement of any prior balances but will impact accounting for business combinations after date of adoption. This guidance was applied to the purchase accounting of Triad Roof Support Systems LLC.

              ASC Topic 810 (previously SFAS No. 160, "Noncontrolling Interests in Consolidated Financial Statements, An Amendment of ARB No. 51") requires all entities to report noncontrolling interests in subsidiaries as a separate component of equity in the consolidated financial statements. A single method of accounting has been established for changes in a parent's ownership interest in a subsidiary that do not result in deconsolidation. Companies no longer recognize a gain or loss on partial disposals of a subsidiary where control is retained. In addition, in partial acquisitions where control is obtained, the acquiring company will recognize and measure at fair value 100% of the assets and liabilities, including goodwill, as if the entire target company had been acquired. We adopted this guidance as of January 1, 2009.

              In May 2009, the FASB issued guidance under ASC Topic 855 (previously SFAS No. 165, "Subsequent Events"), which provided general accounting standards for the disclosure of events that occur after the balance sheet date but before the financial statements are issued or available for issue. This guidance does not apply to subsequent events or transactions that are within the scope of other generally accepted accounting principles that provide different guidance on the accounting treatment of subsequent events. ASC Topic 855 includes a new required disclosure of the date through which an entity, other than a public filer, has evaluated subsequent events and the basis for that date. Such disclosures are required for financial statements issued after June 15, 2009 and are included in these consolidated financial statements.

              In June 2009, the FASB issued guidance under ASC Topic 810 (previously SFAS No. 167, "Amendments to FASB Interpretation No. 46(R)"), which amended the consolidation guidance for variable interest entities, or VIEs. The new guidance requires a company to perform an analysis to determine whether its variable interest gives it a controlling financial interest in a VIE. The amendment, which requires ongoing reassessments, redefines the primary beneficiary as the party that (1) has the power to direct the activities of a VIE that most significantly impact the entity's economic performance and (2) has the obligation to absorb losses of the entity that could potentially be significant to the VIE or the right to receive benefits from the entity that could potentially be significant to the VIE. The guidance includes enhanced disclosures about a company's involvement in a VIE and also eliminates the exemption for qualifying special purpose entities. We evaluated this guidance and determined that certain criteria is not met for consolidation of the VIE and will continue to report the results of the VIE using the equity method of accounting.

              In June 2009, the FASB adopted ASC Topic 105 (previously SFAS No. 168, "The FASB Accounting Standards Codification and the Hierarchy of Generally Accepted Accounting Principles, a replacement of FASB Statement No. 162"), which is effective for periods after September 15, 2009. The ASC became the source of authoritative GAAP applied to nongovernmental entities. Rules and interpretive releases of the SEC under authority of federal securities laws are also sources of authoritative GAAP for SEC registrants. All other non-grandfathered non-SEC accounting literature not included in the ASC is considered non-authoritative. We adopted the ASC as the single source of authoritative nongovernmental generally accepted accounting principles.


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

      Quantitative and Qualitative Disclosures About Market Risk

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

      Commodity Price Risk

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

              Some of the products used in our mining activities, such as diesel fuel, explosives and steel products for roof support used in our underground mining, are subject to price volatility. Through our suppliers, we utilize forward purchases to manage the exposure related to this volatility. A hypothetical increase of $0.10 per gallon for diesel fuel would have reduced net income by $0.8 million for the year ended December 31, 2009 and $0.1$0.3 million for the threesix months ended March 31,June 30, 2010. A hypothetical increase of 10% in steel prices would have reduced net income by $1.2 million for the year ended December 31, 2009 and $0.3$0.4 million for the threesix months ended March 31,June 30, 2010. A hypothetical increase of 10% in explosives prices would have reduced net income by $0.8 million for the year ended December 31, 2009 and $0.1 million for the threesix months ended March 31,June 30, 2010.

      Interest Rate Risk

              We have exposure to changes in interest rates on our indebtedness associated with our credit agreement. During the past year, we have been operating in a period of declining interest rates, and we have managed to take advantage of the trend to reduce our interest expense. A hypothetical increase or decrease in interest rates by 1% would have changed our interest expense by $1.4$1.3 million for the year ended December 31, 2009 and $0.3$0.6 million for the threesix months ended March 31,June 30, 2010.


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      THE COAL INDUSTRY

              Market and industry data and certain other statistical data used in this section are based on independent industry publications, government publications and other published independent sources. In this section, we refer to information regarding the coal industry in the United States and internationally from various third party organizations that are not affiliated with us, including the U.S. Department of Energy's Energy Information Administration, or EIA. The EIA's forecasts are based on a number of variables, and certain unexpected events such as a smaller number of power plants than projected being built, existing plants not significantly increasing capacity or utilization rates, or a change in the number of planned plant retirements among other events, could materially alter coal consumption. In addition, if greenhouse gas emissions from coal-fired power plants are subject to extensive new regulation in the United States pursuant to future U.S. treaty obligations, statutory or regulatory changes under the Clean Air Act, or federal or additional state adoption of a greenhouse gas regulatory scheme, or if reductions in greenhouse gas emissions are mandated by courts or through other legally enforceable mechanisms, absent other factors, the EIA's projections with respect to the demand for coal may not be realized.

              Coal is a combustible mineral that serves as the primary fuel source for the generation of electric power and as a vital ingredient in the production of steel. According to the World Coal Institute, or WCI, coal fuels approximately 41% of global electricity generation, and approximately 68% of global steel production utilizes coal in the manufacturing process. In general, coal of all geological composition is characterized by end use as either steam coal, also known as thermal coal, or metallurgical coal. Nearly half of the United States' electricity is produced by burning steam coal. Metallurgical coal is heated to produce coke, which is used in smelting iron ore to make steel.

              According to theBP Statistical Review of World Energy June 2010, or the BP Review, coal remains the world's most abundant fossil fuel, with a global reserve to production ratio of approximately 119 years. Coal is the least expensive fossil fuel when measured based on the cost per Btu. Due to low cost and available supply, coal represented approximately 29% of the world energy consumption in 2009, the highest since 1970, according to the BP Review.

              Coal is the most abundant fossil fuel in the United States, representing the vast majority of the nation's total fossil fuel reserves. The United States has the largest proved reserves of coal in the world, with approximately 263 billion tons. The United States is the second largest producer of coal after China. According to the EIA, in 2009 the United States produced approximately 1,072.8 million tons of coal and exported approximately 59.1 million tons of coal. At this production rate, the United States has approximately 245 years of coal supply remaining.

              Key attributes in grading metallurgical coal are its sulfur, ash and moisture content and coking characteristics, as compared to the key attributes in grading steam coal, which are heat value, ash and sulfur content. Metallurgical coal used to make coke must be low in sulfur and requires more thorough cleaning than coal used in power plants, and therefore it commands a higher price per ton than steam coal.

              According to Energy Ventures Analysis, Inc., or EVA, the Central Appalachian region supplies the majority of U.S. metallurgical coal for both domestic consumption and for the export market. EVA estimates that the Central Appalachian region supplied approximately 88% of domestic metallurgical coal and 70% of U.S. exported metallurgical coal during 2008. According to the World Steel Association, or WSA, global steel production is expected to increase approximately 9% in 2010, with continued growth in China and India and increased


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      output from traditional steel-producing nations as steel mill utilization rates recover. The Asian market accounted for almost 15% of U.S. metallurgical coal exports in 2009, increasing approximately 32% in 2009 compared to 2008. In addition, the U.S. exported approximately one million tons of metallurgical coal to China, which had not received U.S. metallurgical coal since 2004.

              Steam coal is used by electric utilities throughout the United States to generate power for industrial, commercial and residential consumption. The United States relies on coal for approximately 45% of its power generation, compared to approximately 23% for natural gas. Demand for electricity has historically been driven by U.S. economic growth, but it can fluctuate from year to year depending on weather patterns. In 2009, electricity consumption in the United States decreased approximately 4.0% from 2008, but the average growth rate in the decade prior to 2009 was approximately 0.7% per year according to EIA estimates. Because coal-fired generation is used in most cases to meet base load requirements, coal consumption has generally grown at the pace of electricity demand growth.

      Recent Coal Market Conditions and Trends

              The unprecedented reduction in U.S. electricity consumption in 2009 led to a decline in coal demand and record inventories. However, as the U.S. and global economies recover, we believe that steam coal consumption and the demand for metallurgical coal will increase and lead to higher prices. This is supported by the following trends:


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      Total Monthly Global Steel Production
      (million metric tons)

      CHARTCHART


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      Coal Pricing

              During the past ten years, the global marketplace for coal has experienced swings in the demand/supply balance. In periods of supply shortfall, as occurred from 2003 to early 2006 and again in late 2007 through late 2008, the prices for coal reached record highs in the United States. The increased worldwide demand for coal was primarily driven by higher prices for oil and natural gas and economic expansion, particularly in China, India and elsewhere in Asia. At the same time, infrastructure and demands and restrictions on exports in China contributed to a tightening of worldwide coal supply, affecting global prices of coal. The growth in China and India caused an increase in worldwide demand for raw materials and a disruption of expected coal exports from China to Japan, Korea and other countries. The recent global economic recession reduced the demand for coal.

              Domestic spot coal prices by producing region can trade at vastly different prices due to coal characteristics and deliverability. Northern Appalachia and Central Appalachia spot coal prices typically trade at a premium to other regions due to its higher quality and closer proximity to transportation. At July 9,August 13, 2010, spot prices for Northern Appalachia and Central Appalachia are trading at prices above the average 2009 delivered prices for electric utilities. The following graph shows the historical spot coal prices for the following areas: Central Appalachia, Northern Appalachia, Illinois Basin, Uinta Basin and Powder River Basin.


      Historical Average Weekly Coal Commodity Spot Prices
      (Dollars per Short Ton)

      CHARTCHART


      Source: EIA

              Although coal production and consumption decreased in 2009, the average delivered price for coal continued to increase, rising for the sixth consecutive year. This was primarily caused by the number of coal contracts that were signed in 2008 during the dramatic rise of spot coal prices. The majority of coal sold in the electric power sector is through long-term supply contracts (generally defined as those having terms of one year or more), in conjunction with spot purchases to supplement the demand. As contracts expire and are renegotiated, the prevailing spot price influences the contract price. Metallurgical coal used in steel production continues to be priced at a large premium to steam coal.


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              The following table details the average delivered prices for coal by end use in the United States over the last five years:

      Average Delivered Price 2005 2006 2007 2008 2009 
       
       ($ per ton)
       

      Electric Utilities

       $31.22 $34.26 $36.06 $41.32 $44.72 

      Independent Power Producers

       $30.39 $33.04 $33.11 $38.98 $39.72 

      Coke Plants/Metallurgical Coal

       $83.79 $92.87 $94.97 $118.09 $143.04 

      Other Industrial Plants

       $47.63 $51.67 $54.42 $63.44 $64.87 

      Commercial/Institutional

             $86.50 $97.28 

      Source: EIA

              Metallurgical coal prices in both the domestic and seaborne export markets increased significantly from 2006 to the third quarter of 2008. However, metallurgical coal prices began weakening in the fourth quarter of 2008 with the global economic downturn. Driven by increased demand for steel used in oil and natural gas production, global infrastructure projects, and the manufacturing of automobiles and consumer durables, metallurgical coal prices have begun to rebound as the global steel market begins to strengthen and U.S. steel plant utilization increases. Prices for seaborne metallurgical and steam coal are moving higher as China and India are increasing imports and traditional Asian-based customers are returning to pre-recession levels of coal consumption. Current spotSpot metallurgical coal prices have increased to the $200 per ton range.range, based on certain contracts entered into by third parties in the first quarter of 2010. The following table, derived from data prepared by the EIA, shows the historical average cost of steam coal and metallurgical coal in the export market.

       
       International Export Prices 
      Average Free Alongside Ship Price 2005 2006 2007 2008 2009 
       
       ($ per ton)
       

      Steam Coal

       $47.64 $46.25 $47.90 $57.35 $73.63 

      Metallurgical Coal

       $81.56 $90.81 $88.99 $134.62 $117.73 

      Source: EIA

      U.S. Coal Producing Regions

              Coal is mined from coal basins throughout the United States, with the major production centers located in the Appalachian, Interior and Western United States regions. The quality of coal varies by region. Heat value, sulfur content, ash content, moisture and suitability for production of metallurgical coal coke are important quality characteristics and are used to determine the best end use for the particular coal types.

              U.S. coal production decreased considerably in 2009, dropping approximately 8.5% to approximately 1,073 million tons. The decline in coal production in 2009 was the largest percent decline since 1958 and the largest tonnage decline recorded by the EIA, based on records beginning in 1949. Furthermore, coal production in the United States in 2010 is expected to total approximately 1,0531,071 million tons, a decrease of approximately 1.9%0.2% compared to 2009. The following depictions, derived from data prepared by the EIA, sets forth production statistics in the three coal producing regions in the United States for the periods indicated.


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      U.S Coal Resources Regions 2008

      CHART

      Annual U.S. Coal Production by Region

      CHARTCHART


      Source: EIA

      Appalachian Region

              The Appalachian region is divided into the Northern, Central and Southern regions. According to the EIA, coal produced in the Appalachian region decreased from approximately 445 million tons in 1994 to 341339 million tons in 2009 primarily as a result of the depletion of economically attractive reserves, permitting issues and increasing costs of production.


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              Northern Appalachia includes Maryland, Ohio, Pennsylvania and northern West Virginia. Coal from this region generally has a heat value of between 10,500 and 13,500 Btu/lb with


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      typical sulfur content ranging from 1.0% to 4.5%. Central Appalachia includes eastern Kentucky, Virginia and southern West Virginia. Coal from this region generally has a sulfur content of 0.7% to 1.5% and a heat value of between 10,000 and 13,500 Btu/lb. Southern Appalachia includes Alabama and Tennessee. Coal from this region typically has a sulfur content of 0.7% to 1.5% and a heat value of between 11,500 and 12,500 Btu/lb.

      Interior Region

              The major coal producing center of the Interior region is the Illinois Basin which includes Illinois, Indiana, and western Kentucky. According to the EIA, coal produced in the Interior region decreased from approximately 180 million tons in 1994 to approximately 148 million tons in 2009. Coal from the Illinois Basin generally has a heat value ranging from 10,000 to 12,500 Btu/lb and has a high sulfur content ranging from 2.0% to 4.0%. Despite its high sulfur content, coal from the Illinois Basin can generally be used by some electric power generation facilities that have installed pollution control devices, such as scrubbers, to reduce emissions.

              Other coal-producing states in the Interior region include Arkansas, Kansas, Louisiana, Mississippi, Missouri, North Dakota, Oklahoma and Texas. The majority of production in the Interior region outside of the Illinois Basin consists of lignite production from Texas and North Dakota. This lignite typically has a heat value of between 5,000 and 12,5008,000 Btu/lb and a sulfur content of between 1.0% and 2.0%.

      Western United States Region

              The Western United States region includes, among other areas, the Powder River Basin, the Western Bituminous region (including the Uinta Basin) and the Four Corners area. According to the EIA, coal produced in the Western United States region increased from approximately 408 million tons in 1994 to approximately 585 million tons in 2009, as competitive mining costs and regulations limiting sulfur dioxide emissions have continued the increased demand for low-sulfur coal over this period and the Bureau of Land Management, or BLM, has been actively leasing reserves through the federal coal leasing process.

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

              The Western Bituminous region includes western Colorado and eastern Utah. The coal from this region typically has a sulfur content of 0.5% to 1.0% and a heat value of between 10,000 and 12,000 Btu/lb.

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

      U.S. Coal Consumption

              Preliminary data shows that total coal consumption declined significantly in 2009, dropping by 10.7% from the 2008 level. Total U.S. coal consumption was 1,000 million tons, a decrease of 120 million tons, with all coal-consuming sectors having lower consumption for the year.


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      Although all sectors had declines, the electric generation sector, which consumes approximately 94% of all the coal in the United States, generally determines total domestic coal consumption.


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              The following table sets forth historical and forecasted coal consumption for U.S. coal as aggregated by the EIA for the periods indicated.indicated:



       Actual Forecasted 
       Actual Forecasted 


       2003 2004 2005 2006 2007 2008 2009 2010 2011 
       2003 2004 2005 2006 2007 2008 2009 2010 2011 


       (in million of tons)
       
       (in million of tons)
       

      Electrical Generation

      Electrical Generation

       1,005 1,016 1,038 1,027 1,045 1,041 937 979 1,003 

      Electrical Generation

       1,005 1,016 1,038 1,027 1,045 1,041 937 986 987 

      Industrial

      Industrial

       61 62 60 60 57 54 45 40 43 

      Industrial

       61 62 60 60 57 54 45 43 43 

      Steel Production

      Steel Production

       24 24 23 23 23 22 16 21 24 

      Steel Production

       24 24 23 23 23 22 16 21 23 

      Residential/Commercial

      Residential/Commercial

       4 5 5 4 4 4 3 3 3 

      Residential/Commercial

       4 5 5 4 4 4 3 3 3 

      Coal to Liquids

      Coal to Liquids

                

      Coal to Liquids

                

      Exports

      Exports

       43 48 50 50 59 82 59 74 74 

      Exports

       43 48 50 50 59 82 59 74 74 
                                             

      Total

       1,137 1,153 1,176 1,163 1,188 1,202 1,059 1,117 1,147 

      Total

       1,137 1,153 1,176 1,163 1,188 1,202 1,059 1,127 1,130 
                                             

      Source: EIA

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

              The following table sets forth the different source fuels used for net electricity generation for 2009, according to the EIA.EIA:

      Electricity Generation Source % of Total
      Electricity
      Generation
       

      Coal

        44.6%

      Natural Gas

        23.3%

      Nuclear

        20.2%

      Hydro

        6.8%

      Renewables Other Than Hydro

        3.6%

      Petroleum and Other

        1.5%
          

      Total

        100.0%
          

      Source: EIA

              The nation's power generation infrastructure was approximately 44.6% coal-fired, according to the EIA for 2009. As a result, coal has consistently maintained approximately a 45% to 52% market share during the past 10 years, principally because of its relatively low cost, reliability and abundance.

              The production of electricity from existing hydroelectric facilities is inexpensive, but its application is limited both by geography and susceptibility to seasonal and climatic conditions. In 2009, non-hydropower renewable power generation accounted for only 3.6% of all the electricity generated in the United States.


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


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


       Actual Projected  Actual Projected 

       2005 2006 2007 2008 2009 2010 2011  2005 2006 2007 2008 2009 2010 2011 

       ($ per million Btu)
        ($ per million Btu)
       

      Distillate Fuel Oil

       $11.50 $13.39 $14.66 $21.46 $13.10 $16.53 $17.69  $11.50 $13.39 $14.66 $21.46 $13.10 $16.48 $17.81 

      Residual Fuel Oil

       $7.00 $7.80 $8.59 $13.68 $8.85 $11.95 $12.47  $7.00 $7.80 $8.59 $13.68 $8.85 $11.92 $12.62 

      Natural Gas

       $8.23 $6.92 $7.09 $9.13 $4.69 $5.45 $5.96  $8.23 $6.92 $7.09 $9.13 $4.69 $5.42 $5.71 

      Coal

       $1.54 $1.69 $1.77 $2.07 $2.21 $2.24 $2.19  $1.54 $1.69 $1.77 $2.07 $2.21 $2.25 $2.20 

      Source: EIA

              Coal is the lowest cost fossil fuel used for base-load electric power generation, being considerably less expensive than natural gas or fuel oil. Coal-fueled generation is also competitive with nuclear power generation on a total cost per megawatt-hour basis.

      Mining Methods

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

      Underground Mining

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

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

              Productivity for underground mining in the United States averages 3.2 tons per employee per hour, according to the EIA.

      Surface Mining

              Surface mining is generally used when coal is found relatively close to the surface, when multiple seams in close vertical proximity are being mined or when conditions otherwise


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      warrant. Surface mining involves the removal of overburden (earth and rock covering the coal) with heavy earth moving equipment and explosives, loading out the coal, replacing the


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      overburden and topsoil after the coal has been excavated and reestablishing vegetation and plant life and making other improvements that have local community and environmental benefit. Overburden is typically removed at mines using explosives in combination with large, rubber-tired diesel loaders. Seam recovery for surface mining is typically 90% or more. Productivity depends on equipment, geological composition and mining ratios and averages 3.6 tons per employee per hour in eastern regions of the United States, according to the EIA.

              Surface-mining methods include area, contour, highwall and mountaintop removal. Area mines are surface mines that remove shallow coal over a broad area where the land is fairly flat. After the coal has been removed, the overburden is placed back into the pit. Contour mines are surface mines that mine coal in steep, hilly or mountainous terrain. A wedge of overburden is removed along the coal outcrop on the side of a hill, forming a bench at the level of the coal. After the coal is removed, the overburden is placed back on the bench to return the hill to its natural slope. Highwall mining is a form of mining in which a remotely controlled continuous miner extracts coal and conveys it via augers, belt or chain conveyors to the outside. The cut is typically a rectangular, horizontal cut from a highwall bench, reaching depths of several hundred feet or deeper. A highwall is the unexcavated face of exposed overburden and coal in a surface mine. Mountaintop removal mines are special area mines used where several thick coal seams occur near the top of a mountain. Large quantities of overburden are removed from the top of the mountains, and this material is used to fill in valleys next to the mine.

      Transportation

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

              Most electric generators arrange long-term shipping contracts with rail or barge companies to assure stable delivered costs. Transportation can be a large component of a purchaser's total cost. Although the purchaser pays the freight, transportation costs still are important to coal mining companies because the purchaser may choose a supplier largely based on cost of transportation. According to the National Mining Association, in 2008, railroads accounted for approximately 70% of total U.S. coal shipments, while truck movements accounted for approximately 16%. Trucks and overland conveyors haul coal over shorter distances, while barges, Great Lake carriers and ocean vessels move coal to export markets and domestic markets requiring shipment over the Great Lakes. Most coal mines are served by a single rail company, but much of the Powder River Basin is served by two competing rail carriers, the Burlington Northern Santa Fe Railway and the Union Pacific Railroad. Rail competition in this major coal-producing region is important because rail costs constitute a significant portion of the delivered cost of Powder River Basin coal in eastern markets.


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      BUSINESS

      Overview

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

      Our Properties

              We have a geographically diverse asset base with coal reserves located in Central Appalachia, Northern Appalachia, the Illinois Basin and the Western Bituminous region. As of March 31, 2010, we controlled an estimated 285.4 million tons of proven and probable coal reserves, consisting of an estimated 272.9 million tons of steam coal and an estimated 12.5 million tons of metallurgical coal. In addition, as of March 31, 2010, we controlled an estimated 122.2 million tons of non-reserve coal deposits. As of March 31, 2010, Rhino Eastern LLC, a joint venture in which we own a 51% membership interest and for which we serve as manager, controlled an estimated 22.4 million tons of proven and probable coal reserves at the Rhino Eastern mining complex located in Central Appalachia, consisting entirely of premium mid-vol and low-vol metallurgical coal, and an estimated 34.3 million tons of non-reserve coal deposits. Our and the joint venture's proven and probable coal reserves and non-reserve coal deposits were the same in all material respects as of December 31, 2009. We currently operate twelveeleven mines, including sevensix underground and five surface mines, located in Kentucky, Ohio, Colorado and West Virginia. In addition, our joint venture currently operates one underground mine in West Virginia. The number of mines that we operate may vary from time to time depending on a number of factors, including the existing demand for and price of coal, depletion of economically recoverable reserves and availability of experienced labor. Excluding results from the joint venture, for the three monthsyear ended MarchDecember 31, 2010,2009, we produced approximately 1.04.7 million tons of coal, purchased approximately 2.0 million tons of coal and sold approximately 0.96.7 million tons of coal, approximately 99% of which were pursuant to supply contracts. Excluding results from the joint venture, for the six months ended June 30, 2010, we produced approximately 2.1 million tons of coal and sold approximately 2.0 million tons of coal, approximately 97% of which were pursuant to supply contracts. Additionally, the joint venture produced and sold approximately 0.2 million tons and approximately 0.1 million tons of premium mid-vol metallurgical coal for the year ended December 31, 2009 and the threesix months ended March 31,June 30, 2010, respectively.

              Since our predecessor's formation in 2003, we have significantly grown our coal reserves. Since April 2003, we have completed numerous coal asset acquisitions with a total purchase price of approximately $208.3 million. Through these acquisitions and coal lease transactions, we have substantially increased$223.3 million, including our proven and probable coal reserves and non-reserve coal deposits. We expect to complete the acquisition in August 2010 of certain mining assets of C.W. Mining Company out of bankruptcy for approximately $15.0 million.bankruptcy. The assets to be acquired are located in Emery and Carbon Counties, Utah and include coal reserves and non-reserve coal deposits, underground mining equipment and infrastructure, an overland belt conveyor system, a loading facility and support facilities. We intend to fund the asset acquisition with borrowings underThrough these acquisitions and coal lease transactions, we have substantially increased our credit agreement.proven and probable coal reserves and non-reserve coal deposits.

              In addition, we have successfully grown our production through internal development projects. Between 2004 and 2006, we invested approximately $19.0 million in the Hopedale mine located in Northern Appalachia to develop the estimated 18.5 million tons of proven and


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      probable coal reserves at the mine. The Hopedale mine produced approximately 1.5 million tons of coal for the year ended December 31, 2009 and approximately 0.30.7 million tons of coal for the


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      three six months ended March 31,June 30, 2010. In 2007, we completed initial development of Mine 28, a new underground high-vol metallurgical coal mine at the Rob Fork mining complex located in Central Appalachia. We finished additional development work on Mine 28 in 2009, which completes all major foreseen development projects for the life of these reserves. Mine 28 produced approximately 0.4 million tons of metallurgical coal for the year ended December 31, 2009 and approximately 0.10.2 million tons of metallurgical coal for the threesix months ended March 31,June 30, 2010. As of March 31, 2010, we also controlled or managed a significant amount of undeveloped proven and probable coal reserves. 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.

              The following table summarizes our and the joint venture's mining complexes, production and reserves by region:



        
        
       Production for the (3)  
        
        
        
        
        
       
        
        
       Production for the (3)  
        
        
        
        
        
       


        
        
       As of March 31, 2010 (4) 
        
        
       As of March 31, 2010 (4) 


        
        
        
       Three
      Months
      Ended
      March 31,
      2010
       
        
        
        
       Six
      Months
      Ended
      June 30,
      2010
       


        
        
        
       Reserves  
        
        
       
        
        
        
       Reserves  
        
        
       


       Type of
      Production (1)
        
       Year Ended
      December 31,
      2009
       Average
      Heat
      Value
       Average
      Sulfur
      Content
       Steam/
      Metallurgical
      Reserves
       
       Type of
      Production (1)
        
       Year Ended
      December 31,
      2009
       Average
      Heat
      Value
       Average
      Sulfur
      Content
       Steam/
      Metallurgical
      Reserves
       
      RegionRegion Transportation (2) Proven Three
      Months
      Ended
      March 31,
      2010
      Proven Probable Region Transportation (2) Proven Six
      Months
      Ended
      June 30,
      2010
      Proven Probable 


        
        
       (in million
      tons)

       (in million
      tons)

       (Btu/lb)
       (%)
       (in million
      tons)

       
        
        
       (in million
      tons)

       (in million
      tons)

       (Btu/lb)
       (%)
       (in million
      tons)

       

      Central Appalachia

      Central Appalachia

         

      Central Appalachia

         

      Tug River Complex (KY, WV)

      Tug River Complex (KY, WV)

       U, S Truck, Barge, Rail (NS) 0.5 0.1 28.1 6.7 12,946 1.21 28.8/6.0 

      Tug River Complex (KY, WV)

       U, S Truck, Barge, Rail (NS) 0.5 0.2 28.1 6.7 12,946 1.21 28.8/6.0 

      Rob Fork Complex (KY)

      Rob Fork Complex (KY)

       U, S Truck, Barge, Rail (CSX) 1.2 0.3 26.2 22.6 3.6 13,374 1.14 19.7/6.5 

      Rob Fork Complex (KY)

       U, S Truck, Barge, Rail (CSX) 1.2 0.5 26.2 22.6 3.6 13,374 1.14 19.7/6.5 

      Deane Complex (KY)

      Deane Complex (KY)

       U Rail (CSX) 0.6 0.1 40.8 24.2 16.6 13,448 0.91 40.8/— 

      Deane Complex (KY)

       U Rail (CSX) 0.6 0.2 40.8 24.2 16.6 13,448 0.91 40.8/— 

      Northern Appalachia

      Northern Appalachia

         

      Northern Appalachia

         �� 

      Hopedale Complex (OH)

      Hopedale Complex (OH)

       U Truck, Rail (OHC, WLE) 1.5 0.3 18.5 12.7 5.8 12,994 2.32 18.5/— 

      Hopedale Complex (OH)

       U Truck, Rail (OHC, WLE) 1.5 0.7 18.5 12.7 5.8 12,994 2.32 18.5/— 

      Sands Hill Complex (OH)

      Sands Hill Complex (OH)

       S Truck, Barge 0.7 0.2 8.6 8.3 0.3 10,611 2.51 8.6/— 

      Sands Hill Complex (OH)

       S Truck, Barge 0.7 0.3 8.6 8.3 0.3 10,611 2.51 8.6/— 

      Leesville Field (OH)

      Leesville Field (OH)

       U Rail (OHC, WLE)   26.8 7.8 19.0 13,152 2.21 26.8/— 

      Leesville Field (OH)

       U Rail (OHC, WLE)   26.8 7.8 19.0 13,152 2.21 26.8/— 

      Springdale Field (PA)

      Springdale Field (PA)

       U Barge   13.8 8.8 5.0 13,443 1.72 13.8/— 

      Springdale Field (PA)

       U Barge   13.8 8.8 5.0 13,443 1.72 13.8/— 

      Illinois Basin

      Illinois Basin

         

      Illinois Basin

         

      Taylorville Field (IL)

      Taylorville Field (IL)

       U Rail (NS)   109.5 38.8 70.7 12,085 3.85 109.5/— 

      Taylorville Field (IL)

       U Rail (NS)   109.5 38.8 70.7 12,085 3.85 109.5/— 

      Western Bituminous

      Western Bituminous

         

      Western Bituminous

         

      McClane Canyon Mine (CO)

      McClane Canyon Mine (CO)

       U Truck 0.3 0.1 6.4 4.4 2.0 11,675 0.59 6.4/— 

      McClane Canyon Mine (CO)

       U Truck 0.3 0.1 6.4 4.4 2.0 11,675 0.59 6.4/— 
                                         

      Total

           4.7 1.0 285.4 155.7 129.7     272.9/12.5 

      Total

           4.7 2.1 285.4 155.7 129.7     272.9/12.5 
                                         

      Central Appalachia

      Central Appalachia

         

      Central Appalachia

         

      Rhino Eastern Complex (WV) (5)

      Rhino Eastern Complex (WV) (5)

       U Truck, Rail (NS, CSX) 0.2 0.1 22.4 13.7 8.7 13,999 0.64 —/22.4 

      Rhino Eastern Complex (WV) (5)

       U Truck, Rail (NS, CSX) 0.2 0.1 22.4 13.7 8.7 13,999 0.64 —/22.4 

      (1)
      Indicates mining methods that could be employed at each complex and does not necessarily reflect current methods of production. U = underground; S = surface.
      (2)
      NS = Norfolk Southern Railroad; CSX = CSX Railroad; OHC = Ohio Central Railroad; WLE = Wheeling & Lake Erie Railroad.
      (3)
      Total production based on actual amounts and not rounded amounts shown in this table.
      (4)
      Represents recoverable tons.
      (5)
      Owned by a joint venture in which we have a 51% membership interest and for which we serve as manager. Amounts shown include 100% of the reserves and production.

      Our Business Strategy

              Our principal business strategy is to safely, efficiently and profitably produce and sell both steam and metallurgical coal from our diverse asset base in order to maintain and, over time,


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      increase our quarterly cash distributions. Our plan for executing this strategy includes the following key components:


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      Our Competitive Strengths

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


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