S-1 1 a2184726zs-1.htm FORM S-1

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As filed with the Securities and Exchange Commission on April 15, 2008

Registration No. 333-

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

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

Rhino Resource Partners, L.P.
(Exact Name of Registrant as Specified in Its Charter)

Delaware (State or Other Jurisdiction of Incorporation or Organization)	1221 (Primary Standard Industrial Classification Code Number)	56-2558621 (I.R.S. Employer Identification Number)
3120 Wall Street, Suite 310 Lexington, Kentucky 40513 (859) 389-6500 (Address, Including Zip Code, and Telephone Number, Including Area Code, of Registrant's Principal Executive Offices)
Nicholas R. Glancy 3120 Wall Street, Suite 310 Lexington, Kentucky 40513 (859) 389-6500 (Name, Address, Including Zip Code, and Telephone Number, Including Area Code, of Agent for Service)

Copies to:
Mike Rosenwasser Charles E. Carpenter Vinson & Elkins L.L.P. 666 Fifth Avenue 26th Floor New York, New York 10103 (212) 237-0000		G. Michael O'Leary W. Mark Young Andrews Kurth LLP 600 Travis Suite 4200 Houston, Texas 77002 (713) 220-4200

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

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

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

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

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

Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, or a smaller reporting company. See the 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

CALCULATION OF REGISTRATION FEE

Title of securities to be registered	Proposed maximum aggregate offering price (1)(2)	Amount of registration fee (3)


Common units representing limited partner interests	$115,000,000	$4,520.00

(1): Includes common units issuable upon exercise of the underwriters' option to purchase additional common units.
(2): Estimated solely for the purpose of calculating the registration fee pursuant to Rule 457(o).
(3): Pursuant to Rule 457(p), the registration fee is offset by the registration fee of $9,690.19 previously paid by the registrant in connection with its registration statement on Form S-1 (File No. 333-133348) filed on April 18, 2006.

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

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

Subject to Completion, dated April 15, 2008

PROSPECTUS

5,000,000 Common Units
Representing Limited Partner Interests

This is an initial public offering of our common units. We expect the initial public offering price to be between $ and $ per common unit. Prior to this offering, there has been no public market for the common units. We intend to apply to list our common units on the NASDAQ Global Select Market under the symbol "RRLP."

Investing in our common units involves risks. See "Risk Factors" beginning on page 20.

These risks include the following:

•: 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.
•: The assumptions underlying the forecast of cash available for distribution that we include in "Cash Distribution Policy and Restrictions on Distributions" are inherently uncertain and subject to significant risks that could cause actual results to differ materially from those forecasted.
•: A decline in coal prices could adversely affect our results of operations and cash available for distribution to our unitholders.
•: Our mining operations are subject to extensive and costly laws and regulations, and such current and future laws and regulations could increase current operating costs or limit our ability to produce coal.
•: Our partnership agreement limits our general partner's fiduciary duties to unitholders and restricts the remedies available to unitholders for actions taken by our general partner that might otherwise constitute breaches of fiduciary duty.
•: Our general partner and its affiliates have conflicts of interest, and their limited fiduciary duties to unitholders may permit them to favor their own interests to the detriment of our unitholders.
•: Our sponsor, Wexford, and affiliates of our general partner may compete with us.
•: Unitholders have limited voting rights and are not entitled to elect our general partner or its directors or initially to remove our general partner without its consent.
•: Unitholders will experience immediate and substantial dilution of $15.56 per common unit.
•: 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.
•: 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.
•: Unitholders will be required to pay taxes on their share of our income even if they do not receive any cash distributions from us.

	Per Common Unit	Total
Public Offering Price	$	$
Underwriting Discount	$	$
Proceeds to Rhino Resource Partners, L.P. (before expenses)	$	$

We have granted the underwriters a 30-day option to purchase up to an additional 750,000 common units on the same terms and conditions as set forth above if the underwriters sell more than 5,000,000 common units in this offering.

Neither the Securities and Exchange Commission nor any state securities commission has approved or disapproved of these securities or passed upon the accuracy or adequacy of this prospectus. Any representation to the contrary is a criminal offense.

Lehman Brothers, on behalf of the underwriters, expects to deliver the common units on or about , 2008.

LEHMAN BROTHERS

, 2008

[ARTWORK TO COME]

TABLE OF CONTENTS

SUMMARY		1
RISK FACTORS		20
	Risks Inherent in Our Business	20
	Risks Inherent in an Investment in Us	35
	Tax Risks	42
USE OF PROCEEDS		47
CAPITALIZATION		48
DILUTION		49
CASH DISTRIBUTION POLICY AND RESTRICTIONS ON DISTRIBUTIONS		50
	General	50
	Minimum Quarterly Distribution Rate	52
	Pro Forma and Forecasted Results of Operations and Cash Available for Distribution	53
HOW WE MAKE CASH DISTRIBUTIONS		62
	Distributions of Available Cash	62
	Operating Surplus and Capital Surplus	63
	Subordination Period	66
	Incentive Distribution Rights	69
	Percentage Allocations of Available Cash from Operating Surplus	69
	Distributions from Capital Surplus	70
	Adjustment to the Minimum Quarterly Distribution and Target Distribution Levels	71
	Distributions of Cash Upon Liquidation	71
SELECTED HISTORICAL AND PRO FORMA CONSOLIDATED FINANCIAL AND OPERATING DATA		74
MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS		78
	Overview	78
	Recent Trends and Economic Factors Affecting the Coal Industry	79
	Results of Operations	80
	Liquidity and Capital Resources	98
	Impact of Inflation	102
	Critical Accounting Policies and Estimates	102
	Recent Accounting Pronouncements	106
	Quantitative and Qualitative Disclosures About Market Risk	107
THE COAL INDUSTRY		108
	Recent Coal Market Conditions and Trends	108
	Coal Pricing	109
	Coal Markets	110
	Coal Characteristics	111
	Coal Regions	112
	U.S. Coal Production by Region	113
	Demand for U.S. Coal Production	113
	Mining Methods	115
	Transportation	116
BUSINESS		117
	Overview	117
	Business Strategies	118
	Competitive Strengths	119
	Our History	121
	Our Sponsor	123
	Coal Operations	124
	Coal Reserves and Non-Reserve Coal Deposits	127
	Limestone	131
	Other Natural Resource Assets	131
	Customers	131
	Suppliers	133
	Competition	133
	Regulation and Laws	133
	Office Facilities	142
	Employees	142
	Legal Proceedings	142
MANAGEMENT		143
	Management of Rhino Resource Partners, L.P.	143
	Directors and Executive Officers	143
	Payments to Our General Partner and Wexford	145
	Executive Compensation	145
	Employment Agreements	148
	Compensation of Directors	148
	Long-Term Incentive Plan	149
	401(k) Plan	151
SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT		152

CERTAIN RELATIONSHIPS AND RELATED PARTY TRANSACTIONS		153
	Distributions and Payments to Our General Partner and Its Affiliates	153
	Ownership Interests of Certain Executive Officers and Directors of Our General Partner	154
	Contribution Agreement	154
	Colorado Mining Agreement	155
	Shared Services Agreement	155
CONFLICTS OF INTEREST AND FIDUCIARY DUTIES		156
	Conflicts of Interest	156
	Fiduciary Duties	160
DESCRIPTION OF THE COMMON UNITS		163
	The Units	163
	Transfer Agent and Registrar	163
	Transfer of Common Units	163
THE PARTNERSHIP AGREEMENT		165
	Organization and Duration	165
	Purpose	165
	Power of Attorney	165
	Capital Contributions	165
	Voting Rights	166
	Limited Liability	167
	Issuance of Additional Securities	168
	Amendment of Our Partnership Agreement	169
	Merger, Sale or Other Disposition of Assets	171
	Termination and Dissolution	171
	Liquidation and Distribution of Proceeds	172
	Withdrawal or Removal of Our General Partner	172
	Transfer of General Partner Interest	174
	Transfer of Ownership Interests in Our General Partner	174
	Transfer of Incentive Distribution Rights	174
	Change of Management Provisions	174
	Limited Call Right	175
	Meetings; Voting	175
	Status as Limited Partner or Assignee	176
	Non-Citizen Assignees; Redemption	176
	Indemnification	177
	Reimbursement of Expenses	177
	Books and Reports	177
	Right to Inspect Our Books and Records	178
	Registration Rights	178
UNITS ELIGIBLE FOR FUTURE SALE		179
MATERIAL TAX CONSEQUENCES		180
	Partnership Status	180
	Limited Partner Status	182
	Tax Consequences of Unit Ownership	182
	Tax Treatment of Operations	188
	Disposition of Common Units	192
	Uniformity of Units	194
	Tax-Exempt Organizations and Other Investors	195
	Administrative Matters	196
	State, Local, Foreign and Other Tax Considerations	198
INVESTMENT IN RHINO RESOURCE PARTNERS, L.P. BY EMPLOYEE BENEFIT PLANS		199
UNDERWRITING		200
	Commissions and Expenses	200
	Option to Purchase Additional Units	200
	Lock-Up Agreements	201
	Offering Price Determination	202
	Indemnification	202
	Stabilization, Short Positions and Penalty Bids	202
	Electronic Distribution	203
	NASDAQ Global Select Market	203
	Discretionary Sales	203
	Stamp Taxes	203
	Relationships/NASD Conduct Rules	203
	Selling Restrictions	204
VALIDITY OF THE COMMON UNITS		205
EXPERTS		205
WHERE YOU CAN FIND MORE INFORMATION		205
FORWARD-LOOKING STATEMENTS		206
INDEX TO FINANCIAL STATEMENTS		F-1
FORM OF FIRST AMENDED AND RESTATED AGREEMENT OF LIMITED PARTNERSHIP OF RHINO RESOURCE PARTNERS, L.P.		A-1
GLOSSARY OF TERMS		B-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 common units means that information contained in this prospectus is correct after the date of this prospectus. This prospectus is not an offer to sell or solicitation of an offer to buy these common units in any circumstances under which the offer or solicitation is unlawful.

Until , 2008 (25 days after the date of this prospectus), all dealers that buy, sell or trade our common 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.

iii

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 page20 for information about important risks that you should consider before buying our common units.

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

References in this prospectus to "Rhino Resource Partners, L.P.," "we," "our," "us" or like terms when used in a historical context refer to the businesses of our predecessor, Rhino Energy LLC and its subsidiaries, that are being contributed to Rhino Resource Partners, L.P. in connection with this offering. When used in the present tense or prospectively, those terms refer to Rhino Resource Partners, L.P. and its subsidiaries. References to our general partner refer to Rhino GP LLC. We include a glossary of some of the terms used in this prospectus as Appendix B.

Rhino Resource Partners, L.P.

We are a growth-oriented Delaware limited partnership formed to control and operate coal properties and related assets. We have a geographically diverse asset base with coal reserves located in Central Appalachia, Northern Appalachia, the Illinois Basin and Colorado. For the year ended December 31, 2007, we produced approximately 7.1 million tons of coal and sold approximately 8.2 million tons of coal. As of October 31, 2007, we controlled approximately 222.3 million tons of proven and probable coal reserves and approximately 97.8 million tons of non-reserve coal deposits. We completed the acquisitions of the Sands Hill mining complex located in Northern Appalachia in December 2007 and the Deane mining complex located in Central Appalachia in February 2008 and entered into a lease with respect to the Bolt field located in Central Appalachia in February 2008, which together added a total of approximately 33.9 million tons of proven and probable coal reserves and approximately 28.7 million tons of non-reserve coal deposits. We expect to produce approximately 1.8 million tons of coal in 2009 from our recently acquired mining complexes. We produce high quality coal that is sold in both the steam and metallurgical coal markets. We market our steam coal primarily to electric utilities, the majority of which are rated investment grade. The metallurgical coal that we produce is sold for end use by domestic and international steel producers.

Since our predecessor's formation in 2003, we have significantly grown our asset base through acquisitions of both strategic assets and leasehold interests, as well as through internal development projects. Since April 2003, we have completed numerous asset acquisitions with a total purchase price of approximately $173.9 million. Through these acquisitions and other coal lease transactions, we have significantly increased our proven and probable coal reserves and non-reserve coal deposits. Our acquisition strategy is focused on assets with high quality coal characteristics that are strategically located within strong and growing markets. We also base our acquisition decisions on the operating cost structure of a group of assets, targeting those assets for which we believe we can optimize margins or reduce costs.

completed development of a new underground metallurgical coal mine at the Rob Fork mining complex located in Central Appalachia. The mine produced approximately 650,000 tons of coal for the year ended December 31, 2007. We also control proven and probable coal reserves that are currently undeveloped of approximately (1) 102.4 million tons in the Taylorville field located in the Illinois Basin, (2) 16.7 million tons in the Leesville field located in Northern Appalachia, (3) 15.3 million tons in the Bolt field and (4) 13.8 million tons in the Springdale field located in Northern Appalachia. These reserves can be developed and produced over time as industry and regional conditions permit. We believe our existing asset base will continue to provide attractive internal growth projects.

We believe our sponsor, Wexford Capital LLC ("Wexford"), a Securities and Exchange Commission ("SEC") registered investment advisor with approximately $7.0 billion of assets under management, will provide us with access to potential acquisitions. After this offering, Wexford will control approximately 19.3 million tons of proven and probable coal reserves in Colorado. We believe that Wexford will develop these reserves, including applying for permits and developing the infrastructure necessary for mining these reserves, and will also seek to acquire substantial adjacent coal reserves. If Wexford is successful in developing these coal reserves and acquiring additional reserves, we expect that Wexford may offer these assets to us in the future. However, we cannot assure you that these assets or any other assets that Wexford owns will be offered to, or purchased by, us or on terms favorable to us. Please read "Business—Our Sponsor."

For the year ended December 31, 2007, we generated revenues of approximately $403.5 million and net income of approximately $30.7 million. As of December 31, 2007, we had sales commitments for 84%, 43% and 16% of our estimated coal production of approximately 8.6 million tons, 8.5 million tons and 9.3 million tons for the years ending December 31, 2008, 2009 and 2010, respectively. The following table summarizes our coal operations and reserves by region:

	Production for the Year Ended December 31, 2007	As of October 31, 2007(1)
Region	Production for the Year Ended December 31, 2007	Proven & Provable Reserves	Average Heat Value	Average Sulfur Content	Type of Mines	Steam / Metallurgical Reserves	Transportation(2)
	(in million tons)	(in million tons)	(Btu/lb)	(%)		(in million tons)
Central Appalachia
Tug River Complex (KY, WV)	2.3	36.3	12,808	1.23	Underground and Surface	32.8/3.5	Truck, Barge, Rail (NS)
Rob Fork Complex (KY)	3.3	34.5	12,832	1.08	Underground and Surface	25.7/8.8	Truck, Barge, Rail (CSX)
Deane Complex (KY)(1)	n/a	7.2	13,196	1.55	Underground	7.2/—	Rail (CSX)
Bolt Field (WV)(1)	n/a	15.3	14,094	0.57	Underground	15.3/—	Rail (CSX)
Northern Appalachia
Hopedale Complex (OH)	1.3	17.1	13,026	2.18	Underground	17.1/—	Truck, Barge, Rail (OHC)
Sands Hill Complex (OH)(1)	0.1	11.4	11,830	6.03	Surface	11.4/—	Truck, Barge
Leesville Field (OH)	—	16.7	13,152	2.21	Underground	16.7/—	Rail (OHC)
Springdale Field (PA)	—	13.8	13,443	1.72	Underground	13.8/—	Barge
Illinois Basin
Taylorville Field (IL)	—	102.4	12,084	3.83	Underground	102.4/—	Rail (NS)
Colorado
McClane Canyon Mine (CO)	0.2	1.5	11,522	0.57	Underground	1.5/—	Truck

Total	7.1	256.2

(1): Information regarding the Deane mining complex is as of the acquisition date, February 8, 2008; the Bolt field is as of the lease date, February 15, 2008; and the Sands Hill mining complex is as of the acquisition date, December 14, 2007. Excludes information regarding approximately 19.3 million tons of proven and probable coal reserves in Colorado to be controlled by Wexford after this offering.
(2): NS = Norfolk Southern Railroad; CSX = CSX Railroad; OHC = Ohio Central Railroad.

Business Strategies

Our primary business objective is to increase cash available for distribution by continuing to execute the following strategies:

•: Maximize profitability and maintain stable cash flows;
•: Grow our business through internal development opportunities;
•: Selectively expand our operations through strategic acquisitions; and
•: Focus on excellence in safety and environmental stewardship.

Competitive Strengths

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

•: We have an attractive blend of short-term and longer-term sales contracts as well as uncommitted coal to sell on the spot market.
•: We have significant internal expansion opportunities.
•: We have a proven track record of successful acquisitions.
•: Our mining activities are strategically located.
•: We offer a variety of high quality steam and metallurgical coal that meets our customers' needs.
•: We have vertically integrated many of our operations to control operating costs.
•: We have a strong credit profile.
•: We have an experienced and dedicated sponsor.

Recent Coal Market Conditions and Trends

The coal sector has become increasingly global in nature, and as a result, events in certain regions of the world are impacting market dynamics across the globe, including in the eastern United States. The coal sector, both globally and in the United States, has recently benefited from favorable market fundamentals. Currently, the global supply and demand balance for coal, as well as the overall increase in prices for commodities such as natural gas and crude oil, has created a strong price environment for coal. Coal prices in certain regions such as Central and Northern Appalachia are at the highest levels experienced in the past decade. Below is a list of certain developments around the world that are impacting the coal sector:

•: Demand for coal by emerging global economies, in particular China and India, continues to increase.
•: Traditional exporters of coal to Asia and other regions around the world are challenged to meet the growing demand for coal, which is creating export opportunities for other coal producers, particularly those located in the eastern United States.
•: The continued weakness of the U.S. dollar is also improving the competitiveness of U.S. exports.
•: Flooding in Australia's central Queensland coalfields in January 2008, which disrupted its metallurgical coal production, is causing Asian countries dependent on Australian coal to source coal from other places.

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

The Transactions

We are a Delaware limited partnership formed in January 2006 by affiliates of Wexford to own and operate businesses that have historically been conducted by Rhino Energy LLC.

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

•: Rhino Energy LLC will distribute its ownership interests in CAM-Colorado LLC, an entity that owns certain properties located in Colorado that will not be retained by us, to NR Energy LLC, an entity owned by certain investment funds managed by Wexford ("Wexford Funds");
•: Rhino Energy Holdings LLC, which is also owned by certain Wexford Funds, will contribute 100% of the ownership interests in Rhino Energy LLC to us;
•: we will issue to Rhino Energy Holdings LLC an aggregate of 27,925,200 common units and 3,741,500 subordinated units, representing a combined 84.6% limited partner interest in us;
•: Rhino GP LLC, our general partner, will maintain its 2% general partner interest in us. We will also issue to our general partner the incentive distribution rights, which entitle the holder to increasing percentages, up to a maximum of 10%, of the cash we distribute in excess of $0.425 per unit per quarter; and
•: we will issue 5,000,000 common units to the public, representing a 13.4% limited partner interest in us, and will use the net proceeds from this offering as described under "Use of Proceeds."

Certain executive officers and directors of our general partner are principals of Wexford (collectively, the "Wexford Principals"). Please read "Certain Relationships and Related Party Transactions" for additional information.

Summary of Risk Factors

An investment in our common units involves risks associated with our business, our partnership structure and the tax characteristics of our common units. Those risks are described under the caption "Risk Factors" beginning on page 20 and include, among others:

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.
•: The assumptions underlying the forecast of cash available for distribution that we include in "Cash Distribution Policy and Restrictions on Distributions" are inherently uncertain and subject to significant risks that could cause actual results to differ materially from those forecasted. If we do not achieve the forecasted results, we may not be able to pay the minimum quarterly distribution or any amount on our common units and subordinated units and the market price of our common units may decline materially.
•: A decline in coal prices could adversely affect our results of operations and cash available for distribution to our unitholders.
•: Our mining operations are subject to extensive and costly laws and regulations, and such current and future laws and regulations could increase current operating costs or limit our ability to produce coal.
•: Our mining operations are subject to operating risks that are beyond our control and could adversely affect production levels and increase costs.

•: Fluctuations in transportation costs or disruptions in transportation services could increase competition or impair our ability to supply coal to our customers, which could adversely affect our results of operations and cash available for distribution to our unitholders.
•: A shortage of skilled labor, together with rising labor costs in the mining industry, has increased and may further increase operating costs, which could adversely affect our results of operations and cash available for distribution to our unitholders.
•: Unexpected increases in raw material costs could adversely affect our results of operations and reduce the amount of cash available for distribution to our unitholders.
•: We may be unable to obtain and/or renew permits necessary for our operations, which could prevent us from mining certain reserves.
•: The unavailability of an adequate supply of coal reserves that can be developed or acquired at competitive costs could adversely affect our results of operations and cash available for distribution to our unitholders.
•: Inaccuracies in our estimates of coal reserves and non-reserve coal deposits could result in lower than expected revenues and higher than expected costs.
•: The amount of estimated maintenance and replacement capital expenditures our general partner is required to deduct from operating surplus each quarter is based on our current estimates and could increase in the future, resulting in a decrease in available cash from operating surplus that could be distributed to our unitholders.

Risks Inherent in an Investment in Us

•: Our partnership agreement limits our general partner's fiduciary duties to unitholders and restricts the remedies available to unitholders for actions taken by our general partner that might otherwise constitute breaches of fiduciary duty.
•: Our general partner and its affiliates have conflicts of interest, and their limited fiduciary duties to unitholders may permit them to favor their own interests to the detriment of our unitholders.
•: Our sponsor, Wexford, and affiliates of our general partner may compete with us.
•: Unitholders have limited voting rights and are not entitled to elect our general partner or its directors or initially to remove our general partner without its consent.
•: Unitholders will experience immediate and substantial dilution of $15.56 per common unit.
•: The control of our general partner may be transferred to a third party without unitholder consent.
•: Our general partner has a limited call right that may require unitholders to sell their common units at an undesirable time or price.
•: We may issue additional units without unitholder approval, which would dilute unitholder interests.
•: Our partnership agreement restricts the voting rights of unitholders owning 20% or more of our common units.
•: Cost reimbursements due to our general partner and its affiliates will reduce cash available for distribution to our unitholders.

•: There is no existing market for our units, and a trading market that will provide unitholders with adequate liquidity may not develop. The price of our units may fluctuate significantly, and unitholders could lose all or part of their investment.
•: We will incur increased costs as a result of being a publicly traded partnership.

Tax Risks

•: Our tax treatment depends on our status as a partnership for federal income tax purposes. If the IRS were to treat us as a corporation for 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.
•: 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.
•: 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.
•: 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.
•: 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.
•: Unitholders will be required to pay taxes on their share of our income even if they do not receive any cash distributions from us.
•: Tax gain or loss on the disposition of our common units could be more or less than expected.

Management and Ownership

We are managed and operated by the directors and executive officers of our general partner, Rhino GP LLC. Our general partner is not elected by our unitholders and will not be subject to re-election on a regular basis in the future. Currently, and upon the consummation of this offering, the Wexford Principals will own 100% of the ownership interests in our general partner. Rhino GP LLC will have a board of directors, and unitholders will not be entitled to elect the directors or otherwise directly participate in our management or operation. Certain executive officers and directors of our general partner are Wexford Principals. For information about the executive officers and directors of our general partner, please read "Management—Directors and Executive Officers." Our general partner owes certain fiduciary duties to our unitholders as well as a fiduciary duty to its owners. Our general partner will be liable, as general partner, for all of our debts (to the extent not paid from our assets), except for indebtedness or other obligations that are made specifically nonrecourse to it. Whenever possible, our general partner intends to incur indebtedness or other obligations that are nonrecourse.

Our general partner and its affiliates will not receive any management fee or other compensation in connection with its management of our business, but will be reimbursed for expenses incurred on our behalf. These expenses include the costs of officer and director compensation and benefits properly allocable to us, and all other expenses necessary or appropriate to the conduct of our business and allocable to us. Our partnership agreement provides that our general partner will determine the expenses that are allocable to us.

Our general partner will initially own a 2% general partner interest in us. We will also issue to our general partner the incentive distribution rights, which entitle the holder to increasing percentages, up to a maximum of 10%, of the cash we distribute in excess of $0.425 per unit per quarter, in connection with our initial public offering. Our general partner will be entitled to distributions on its general partner interest and, if specified requirements are met, on its incentive distribution rights. Please read "Certain Relationships and Related Party Transactions."

Principal Executive Offices

Our principal executive offices are located at 3120 Wall Street, Suite 310, Lexington, Kentucky. Our phone number is (859) 389-6500. Our website will be located at http://www.rhinolp.com. We expect to make our periodic reports and other information filed with or furnished to the SEC available, free of charge, through our website, as soon as reasonably practicable after those reports and other information are electronically filed with or furnished to the SEC. Information on our website or any other website is not incorporated by reference into this prospectus and does not constitute a part of this prospectus.

Organizational Structure

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

Public Common Units		13.4	%
Interests of the Wexford Principals and Wexford Funds:
	Common Units	74.6	%
	Subordinated Units	10.0	%
	General Partner Interest	2.0	%

		100.0	%

(1): Certain executive officers and directors of our general partner are Wexford Principals. Please read "Certain Relationships and Related Party Transactions—Ownership Interests of Certain Executive Officers and Directors of Our General Partner."
(2): Wexford Funds owning Rhino Energy Holdings LLC and NR Energy LLC may not be identical.

Summary of Conflicts of Interest and Fiduciary Duties

Rhino GP LLC, our general partner, has a legal duty to manage us in a manner beneficial to our unitholders. This legal duty originates in statutes and judicial decisions and is commonly referred to as a "fiduciary duty." As described herein, this fiduciary duty is limited by our partnership agreement. However, because our general partner is owned by the Wexford Principals, our management team has fiduciary duties to manage the business of Rhino GP LLC in a manner beneficial to the Wexford Principals. As a result of this relationship, conflicts of interest may arise in the future between us and our unitholders, on the one hand, and our general partner and its affiliates, on the other hand. For a more detailed description of the conflicts of interest and fiduciary duties of our general partner, please read "Conflicts of Interest and Fiduciary Duties."

Our partnership agreement limits the liability and reduces the fiduciary duties of our general partner to our unitholders. Our partnership agreement also restricts the remedies available to unitholders for actions that might otherwise constitute breaches of our general partner's fiduciary duty. By purchasing a common unit, unitholders are treated as having consented to various actions contemplated in the partnership agreement and conflicts of interest that might otherwise be considered a breach of fiduciary or other duties under applicable law. Please read "Conflicts of Interest and Fiduciary Duties—Fiduciary Duties" for a description of the fiduciary duties imposed on our general partner by Delaware law, the material modifications of these duties contained in our partnership agreement and certain legal rights and remedies available to unitholders.

For a description of our other relationships with our affiliates, please read "Certain Relationships and Related Party Transactions."

The Offering

Common units offered to the public	5,000,000 common units.
	5,750,000 common units if the underwriters exercise their option to purchase additional common units in full.
Units outstanding after this offering	32,925,200 common units representing an 88.0% limited partner interest in us and 3,741,500 subordinated units representing a 10.0% limited partner interest in us.
	33,675,200 common units representing an 88.2% limited partner interest in us and 3,741,500 subordinated units representing a 9.8% limited partner interest in us if the underwriters exercise their option to purchase additional common units in full.
Use of proceeds	We intend to use the estimated net proceeds of approximately $92.0 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 payable by us, to:
	•	repay approximately $67.0 million of outstanding indebtedness under our credit facility; and
	•	distribute approximately $25.0 million to Rhino Energy Holdings LLC as reimbursement for capital expenditures (expenditures that were capitalized for federal income tax purposes) incurred within the prior 24 months by Rhino Energy LLC with respect to the assets to be contributed to us upon the closing of this offering. Please read "Business—Our History" and "Management's Discussion and Analysis of Financial Condition and Results of Operations—Liquidity and Capital Resources—Capital Expenditures" for information on these capital expenditures.
	The net proceeds from any exercise of the underwriters' option to purchase additional common units may be distributed to Rhino Energy Holdings LLC or used for general partnership purposes, including the repayment of indebtedness.
	Please read "Use of Proceeds."
Cash distributions	We intend to make a minimum quarterly distribution of $0.375 per common unit (or $1.50 per common unit on an annualized basis) to the extent we have sufficient cash after establishment of cash reserves and payment of costs and expenses, including reimbursement of expenses to our general partner and its affiliates.

		Our ability to pay cash distributions at this minimum quarterly distribution rate is subject to various restrictions and other factors described in more detail under "Cash Distribution Policy and Restrictions on Distributions."
		We will adjust the minimum quarterly distribution for the period from the closing of this offering through June 30, 2008 based on the actual length of the period.
		Our partnership agreement requires us to distribute all of our cash on hand at the end of each quarter after the payment of costs and expenses, less reserves established by our general partner in its discretion subject to its fiduciary duty, as modified by our partnership agreement, which requires it to act in good faith. We refer to this cash as "available cash," and we define its meaning in our partnership agreement, in "How We Make Cash Distributions—Distributions of Available Cash—Definition of Available Cash" and in the glossary of terms attached as Appendix B.
		In general, we will pay any cash distributions we make each quarter in the following manner:
		•		first, 98% to the holders of common units and 2% to our general partner, until each common unit has received a minimum quarterly distribution of $0.375 plus any arrearages from prior quarters;
		•		second, 98% to the holders of subordinated units and 2% to our general partner, until each subordinated unit has received a minimum quarterly distribution of $0.375; and
		•		third, 98% to all unitholders, pro rata, and 2% to our general partner, until each unit has received a distribution of $0.425.
		If cash distributions to our unitholders exceed $0.425 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	Marginal Percentage Interest in Distributions
Total Quarterly Distribution			General Partner
Target Amount	Unitholders		General Partner
above $0.425 up to $0.450	96	%	4	%
above $0.450 up to $0.475	94	%	6	%
above $0.475 up to $0.500	92	%	8	%
above $0.500	90	%	10	%

Please read "How We Make Cash Distributions—Incentive Distribution Rights."

		Pro forma cash available for distributions generated during the year ended December 31, 2007 would have been sufficient to allow us to pay the minimum quarterly distribution on only 82.7% of our common units and on none of our subordinated units (or on 80.8% of our common units and on none of our subordinated units, if the underwriters exercise their option to purchase additional common units in full). This represents 72.7% of the total distributions payable to all unitholders and the general partner (or 71.3%, if the underwriters exercise their option to purchase additional common units in full).
		Please read "Cash Distribution Policy and Restrictions on Distributions—Pro Forma and Forecasted Results of Operations and Cash Available for Distribution."
		We have included a forecast of our cash available for distribution for the twelve months ending June 30, 2009 in "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, that we will have sufficient available cash to enable us to pay the full minimum quarterly distribution of $0.375 on all of our common units and on all of our subordinated units for the four quarters ending June 30, 2009. The amount of available cash we need to pay the minimum quarterly distribution for four quarters on our common units, subordinated units and 2% general partner interest to be outstanding immediately after this offering is approximately $56.1 million (or approximately $57.3 million, if the underwriters exercise their option to purchase additional common units in full). Based on our financial forecast and related assumptions, we forecast that our cash available for distribution for the twelve months ending June 30, 2009 will be approximately $95.2 million.
		Although we do not anticipate doing so, distributions out of capital surplus, as opposed to operating surplus, will constitute a return of capital to unitholders and will result in a reduction in the minimum quarterly distribution and target distribution levels. Please read "How We Make Cash Distributions—Effect of a Distribution from Capital Surplus."
Subordination period		Wexford Funds will indirectly own all of our subordinated units. During the subordination period, the subordinated units will not be entitled to receive any distributions until the common units have received the minimum quarterly distribution plus any arrearages from prior quarters. If we do not pay distributions on our subordinated units, our subordinated units will not accrue arrearages for those unpaid distributions. Except as set forth below, the subordination period will extend until the first day of any quarter beginning after June 30, 2013 that we meet certain financial tests included in our partnership agreement.

		If, however, we have earned and paid from operating surplus an amount that equals or exceeds $2.00 (133% of the annualized minimum quarterly distribution) on each outstanding unit for a single four-quarter period, the subordination period will automatically terminate and all of the subordinated units will convert into common units.
		In addition, if we meet the financial tests in our partnership agreement for any three consecutive four-quarter periods ending on or after June 30, 2011, 25% of the subordinated units will convert into common units. If we meet these tests for any three consecutive four-quarter periods ending on or after June 30, 2012, an additional 25% of the subordinated units will convert into common units. The second early conversion of the subordinated units may not occur until at least one year after the first early conversion of subordinated units.
		When the subordination period ends, all subordinated units will convert into common units on a one-for-one basis, and the common units will no longer be entitled to arrearages. Please read "How We Make Cash Distributions—Subordination Period."
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 Securities."
Limited voting rights		Our general partner will manage and operate us. Unlike the holders of common stock in a corporation, you will have only limited voting rights on matters affecting our business. You 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 Funds will own an aggregate of 86.4% of our common and subordinated units (or 84.6% of our common and subordinated units, if the underwriters exercise their option to purchase additional common units in full). This will give Wexford Funds the ability to prevent 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 not less than the then-current market price of the common units. If our general partner and its affiliates reduce their ownership percentage to below 50% of the outstanding common units, the ownership threshold to exercise the limited call rights will be reduced to 80%. Please read "The Partnership Agreement—Limited Call Right."
Non-citizen assignee and redemption		Our general partner at any time may require each limited partner or assignee to furnish information about his nationality, citizenship, or related status. If a limited partner or assignee fails to furnish information about his nationality, citizenship or other related status within 30 days after a request for the information or our general partner determines after receipt of the information that the limited partner or assignee is not an eligible citizen, the limited partner or assignee may be treated as a non-citizen assignee. In addition to other limitations on the rights of an assignee that is not a limited partner, a non-citizen assignee does not have the right to direct the voting of his units and may not receive distributions in kind upon our liquidation. Furthermore, we have the right to redeem all of the common and subordinated units of any holder that is not an eligible citizen or fails to furnish the information requested by our general partner. Please read "The Partnership Agreement—Non-Citizen Assignees; Redemption."
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, 2011, you will be allocated, on a cumulative basis, an amount of federal taxable income for that period that will be % or less of the cash distributed to you with respect to that period. For example, if you receive an annual distribution of $1.50 per unit, we estimate that your average allocable federal taxable income per year will be no more than $ per unit. Please read "Material Tax Consequences—Tax Consequences of Unit Ownership—Ratio of Taxable Income to Distributions" for the basis of this estimate.
Material tax consequences		For a discussion of other 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 intend to apply to list our common units on the NASDAQ Global Select Market under the symbol "RRLP."

Summary Historical and Pro Forma Consolidated Financial and Operating Data

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

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

•: the distribution by Rhino Energy LLC of its ownership interests in CAM-Colorado LLC, an entity that owns certain properties located in Colorado that will not be retained by us, to NR Energy LLC, an entity owned by certain Wexford Funds;
•: the contribution by Rhino Energy Holdings LLC, which is also owned by certain Wexford Funds, of 100% of the ownership interests in Rhino Energy LLC to us;
•: the issuance by us to Rhino Energy Holdings LLC of an aggregate of 27,925,200 common units and 3,741,500 subordinated units, representing a combined 84.6% limited partner interest in us;
•: the issuance by us to our general partner of the incentive distribution rights, which entitle the holder to increasing percentages, up to a maximum of 10%, of the cash we distribute in excess of $0.425 per unit per quarter. Our general partner will also maintain its 2% general partner interest in us; and
•: the issuance by us to the public of 5,000,000 common units, representing a 13.4% limited partner interest in us, and the use of the net proceeds from this offering as described under "Use of Proceeds."

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

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

The following table presents a non-GAAP financial measure, EBITDA, which we use in our business as it is an important supplemental measure of our performance and liquidity. EBITDA means earnings before interest, taxes, depreciation, depletion and amortization. This measure is not calculated or presented in accordance with generally accepted accounting principles ("GAAP"). We explain this measure below and reconcile it to its most directly comparable financial measures calculated and presented in accordance with GAAP.

Maintenance and replacement capital expenditures are those capital expenditures required to maintain or replace our capital asset base. Expansion capital expenditures are those capital expenditures made to increase or expand our capital asset base. Examples of maintenance and replacement capital expenditures include 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 incurred to maintain or replace our capital asset base. 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 incurred to increase or expand our capital asset base.

				Rhino Energy LLC Historical Consolidated									Rhino Resource Partners, L.P. Pro Forma Consolidated
				Year Ended March 31, 2006			Nine Months Ended December 31, 2006			Year Ended December 31, 2007			Year Ended December 31, 2007
				(in thousands, except per unit and per ton data)
Statement of Operations Data:
Total revenues				$	363,959.9		$	300,838.5		$	403,451.8		$	403,443.2
Costs and expenses:
	Cost of operations (exclusive of depreciation, depletion and amortization shown separately below)				291,444.7			238,189.7			318,520.6			318,531.7
	Freight and handling costs				6,342.5			2,768.1			4,020.7			4,020.7
	Depreciation, depletion and amortization				13,744.3			28,471.2			30,749.8			30,749.8
	Selling, general and administrative				17,129.4			18,573.0			15,370.3			15,369.7
	(Gain) loss on sale of assets				(377.2	)		745.8			(944.3	)		(944.3	)
	(Gain) loss on retirement of advance royalties				(236.9	)		2,994.6			(115.3	)		(115.3	)

		Total costs and expenses			328,046.8			291,742.4			367,601.8			367,612.3

Income from operations					35,913.1			9,096.1			35,850.0			35,830.9
Interest and other income (expense):
	Interest expense				(4,976.2	)		(6,498.0	)		(5,579.2	)		(1,800.8	)
	Interest income				412.1			311.7			316.7			316.7
	Other—net				490.7			272.2			—			—

Total interest and other income (expense)					(4,073.4	)		(5,914.1	)		(5,262.5	)		(1,484.1	)

Income before income tax expense and cumulative effect of change in accounting principle					31,839.7			3,182.0			30,587.5			34,346.8
Income tax expense (benefit)					178.4			124.6			(126.3	)		(126.3	)

Net income before cumulative effect of change in accounting principles					31,661.3			3,057.4			30,713.8			34,473.1
Cumulative effect of change in accounting principle—net of taxes					—			—			—			—

Net income				$	31,661.3		$	3,057.4		$	30,713.8		$	34,473.1
Other comprehensive income (loss):
	Change in actuarial gain/(loss) under SFAS No. 158				—			(901.0	)		1,489.4			1,489.4

Net comprehensive income				$	31,661.3		$	2,156.4		$	32,203.2		$	35,962.5

Net income per limited partner unit, basic and diluted:
	Common units												$	1.03
	Subordinated units												$	—
Weighted average number of limited partner units outstanding, basic and diluted:
	Common units													32,925.2
	Subordinated units													3,741.5
Statement of Cash Flows Data:
Net cash provided by (used in):
	Operating activities			$	32,892.0		$	36,859.5		$	52,492.5		$	55,756.7
	Investing activities			$	(34,612.6	)	$	(28,827.6	)	$	(28,097.6	)
	Financing activities			$	(1,886.9	)	$	(9,140.8	)	$	(21,191.5	)
Other Financial Data:
EBITDA(1)				$	50,560.2		$	38,151.2		$	66,916.5		$	66,897.4
Maintenance and replacement capital expenditures				$	32,348.2		$	20,952.4		$	19,047.2		$	19,047.2
Expansion capital expenditures					31,525.1			18,357.0			31,162.5			30,360.8

			Total capital expenditures	$	63,873.3		$	39,309.4		$	50,209.7		$	49,408.0

Balance Sheet Data (at period end):
Cash and cash equivalents	$	1,488.8	$	380.0	$	3,583.4	$	3,583.4
Property and equipment, net	$	180,267.0	$	197,056.1	$	211,657.1	$	193,869.3
Total assets	$	246,759.3	$	248,194.5	$	275,992.2	$	258,200.3
Total liabilities	$	154,028.4	$	153,307.1	$	158,151.7	$	91,352.4
Total debt	$	87,764.1	$	88,570.5	$	83,953.7	$	16,953.7
Members'/partners' equity	$	92,730.9	$	94,887.4	$	117,840.5	$	166,847.8
Operating Data:
Tons of coal sold		7,900.3		6,222.9		8,159.0
Tons of coal produced		7,950.1		6,182.0		7,056.6
Coal revenues per ton(2)	$	44.48	$	47.31	$	48.30
Cost of operations per ton(3)	$	36.89	$	38.28	$	39.04

(1)

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

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

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

The following table presents a reconciliation of EBITDA to the most directly comparable GAAP financial measures, on a historical basis and pro forma basis, as applicable, for each of the periods indicated.

		Rhino Energy LLC Historical Consolidated							Rhino Resource Partners, L.P. Pro Forma Consolidated
		Year Ended March 31, 2006		Nine Months Ended December 31, 2006		Year Ended December 31, 2007			Year Ended December 31, 2007
		(in thousands)
Reconciliation of EBITDA to net income:
Net income		$	31,661.3	$	3,057.4	$	30,713.8		$	34,473.1
Plus:
	Depreciation, depletion and amortization		13,744.3		28,471.2		30,749.8			30,749.8
	Interest expense		4,976.2		6,498.0		5,579.2			1,800.8
	Income tax expense (benefit)		178.4		124.6		(126.3	)		(126.3	)

EBITDA		$	50,560.2	$	38,151.2	$	66,916.5		$	66,897.4

Reconciliation of EBITDA to net cash provided by operating activities:
Net cash provided by operating activities		$	32,892.0	$	36,859.5	$	52,492.5	$	55,756.7
Plus:
	Increase in net operating assets		16,447.4		892.7		10,552.7		11,047.8
	Decrease in provision for doubtful accounts		—		282.8		175.2		175.2
	Gain on sale of assets		377.2		—		944.3		944.3
	Gain on retirement of advance royalties		236.9		—		115.3		115.3
	Interest expense		4,976.2		6,498.0		5,579.2		1,800.8
	Income tax expense		178.4		124.6		—		—
Less:
	Accretion on interest-free debt		321.2		255.1		359.8		359.8
	Amortization of advance royalties		2,186.8		1,098.5		699.7		699.7
	Increase in provision for doubtful accounts		354.4		—		—		—
	Loss on sale of assets		—		745.8		—		—
	Loss on retirement of advance royalties		—		2,994.6		—		—
	Income tax benefit		—		—		126.3		126.3
	Accretion on asset retirement obligations		1,685.5		1,412.4		1,756.9		1,756.9

EBITDA		$	50,560.2	$	38,151.2	$	66,916.5	$	66,897.4

(2): Coal revenues per ton represent total coal revenues, derived from the sale of coal from all business segments, divided by total tons of coal sold for all segments.
(3): Cost of operations per ton represents the cost of operations (exclusive of depreciation, depletion and amortization) from all business segments divided by total tons of coal sold for all segments.

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 minimum quarterly distribution. 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:

•: the level of our operating costs, including reimbursement of expenses to our general partner;
•: prevailing economic and market conditions;
•: difficulties in collecting our receivables because of credit or financial problems of major customers;
•: changes in governmental regulation of the mining industry or the electric utility industry;
•: unfavorable geologic conditions; and
•: force majeure.

In addition, the actual amount of cash we will have available for distribution will depend on other factors such as:

•: the level of capital expenditures we make;
•: the restrictions contained in our credit agreement and our debt service requirements;
•: the cost of acquisitions, if any;
•: fluctuations in our working capital needs;
•: the amount of fees and expenses we incur, including reimbursement of expenses to our general partner;
•: our ability to generate working capital and obtain borrowings to make distributions to our unitholders; and
•: the amount, if any, of cash reserves established by our general partner in its discretion. In establishing cash reserves, our general partner is subject to its fiduciary duty, as modified by our partnership agreement, to the limited partners, which requires it to act in good faith.

The assumptions underlying the forecast of cash available for distribution that we include in "Cash Distribution Policy and Restrictions on Distributions" are inherently uncertain and subject to significant risks that could cause actual results to differ materially from those forecasted. If we do not achieve the forecasted results, we may not be able to pay the minimum quarterly distribution or any amount on our common units and subordinated units and the market price of our common units may decline materially.

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 June 30, 2009. The financial forecast has been prepared by management, and we have not received an opinion or report on it from our or any other independent auditor. The assumptions underlying the forecast are inherently uncertain and are subject to significant business, economic, regulatory and competitive risks, including those discussed below, that could cause actual results to differ materially from those forecasted. If we do not achieve the forecasted results, we may not be able to pay the minimum quarterly distribution or any amount on our common units or subordinated units and the market price of our common units may decline materially.

The amount of available cash we need to pay the minimum quarterly distribution for four quarters on our common units, subordinated units and 2% general partner interest to be outstanding immediately after this offering is approximately $56.1 million (or approximately $57.3 million, if the underwriters exercise their option to purchase additional common units in full). Pro forma available cash to make distributions generated during the year ended December 31, 2007 would not have been sufficient to allow us to pay the full minimum quarterly distribution on all of our common units and therefore would not have allowed us to pay any distributions on our subordinated units during these periods. For a calculation of our ability to make distributions to unitholders based on our pro forma results for the year ended December 31, 2007 and for a forecast of our ability to pay the full minimum quarterly distribution on our common units, subordinated units and 2% general partner interest for the twelve months ending June 30, 2009, 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 are dependent upon the prices we receive for our coal as well as our ability to improve productivity and control costs. Declines in the prices we receive for our coal could adversely affect our results of operations and our ability to make distributions to our unitholders. The prices we receive for coal depend upon factors beyond our control, including:

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

•: the effect of worldwide energy conservation measures.

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

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

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

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

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

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

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

•: mining and processing equipment unavailability and failures and unexpected maintenance problems; and
•: accidents, including fire and explosions from methane.

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

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 source of energy or could make our coal production less competitive than coal produced from other sources.

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

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

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

Efficient mining using modern techniques and equipment requires skilled laborers, preferably with at least a year of experience and proficiency in multiple mining tasks. In the event the shortage of experienced labor continues or worsens or we are unable to train the necessary number of skilled laborers, there could be an adverse impact on our labor productivity and costs and our ability to expand production, which could have an adverse effect on our results of operations and cash available for distribution to our unitholders.

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

Unexpected increases in raw material costs could adversely affect our results of operations and reduce the amount of cash available for distribution to our unitholders.

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

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

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

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

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

The unavailability of an adequate supply of coal reserves that can be developed or acquired at competitive costs could adversely affect our results of operations and cash available for distribution to our unitholders.

Our results of operations and cash available for distribution depend substantially on our ability to mine coal reserves that have the geological characteristics that enable them to be mined at competitive costs and to meet the coal quality needed by our customers. Because our reserves decline as we mine our coal, our future success and growth depend, in part, upon our ability to acquire additional coal reserves that are economically recoverable. Replacement reserves may not be available when required or, if available, may not be capable of being mined at costs comparable to those characteristic of the depleting mines. 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 or cash available for distribution to our unitholders. Exhaustion of reserves at particular mines also may have an adverse effect on our operating results that is disproportionate to the percentage of overall production represented by such mines. Our ability to obtain other reserves in the future could be limited by restrictions under our existing or future debt agreements, competition from other coal companies for attractive properties, the lack of suitable acquisition candidates or the inability to acquire coal properties on commercially reasonable terms.

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

We base our coal reserve estimates and non-reserve coal deposit information on engineering, economic and geological data assembled and analyzed by our staff, which includes various engineers and geologists, and which is periodically reviewed by outside firms. The estimates of coal reserves and non-reserve coal deposits as to both quantity and quality are annually updated to reflect the production of coal from the reserves and new drilling or other data received. There are numerous uncertainties inherent in estimating quantities and qualities of coal reserves and non-reserve coal deposits and costs to mine recoverable reserves, including many factors beyond our control. Estimates of economically recoverable coal reserves and net cash flows necessarily depend upon a number of variable factors and assumptions, all of which may vary considerably from actual results such as:

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

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

The amount of estimated maintenance and replacement capital expenditures our general partner is required to deduct from operating surplus each quarter is based on our current estimates and 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 and replacement capital expenditures as opposed to actual maintenance and replacement capital expenditures in order to reduce disparities in operating surplus caused by fluctuating maintenance and replacement capital expenditures, such as mining development costs. Our initial annual estimated maintenance and replacement capital expenditures for purposes of calculating operating surplus will be $33.0 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 and replace our depleting capital asset base, which we believe to be reasonable. This amount has been taken into consideration in calculating our forecast of cash available for distribution in "Cash Distribution Policy and Restrictions on Distributions." The amount of estimated maintenance and replacement 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. The

deduction of estimated maintenance and replacement capital expenditures in calculating operating surplus results in a decrease in available cash from operating surplus that could be distributed to our unitholders and makes it more difficult for us to raise our distribution above the minimum quarterly distribution.

Our ability to expand our cash available for distribution may be adversely affected if we are unable to acquire other attractive natural resource assets or are unable to successfully manage or grow these assets once we acquire them.

Our primary business objective is to expand our cash available for distribution by continuing to execute various strategies. One of our business strategies is to identify and acquire selected, attractive natural resource assets in which we or our sponsor have substantial experience and where we may have a strategic advantage. However:

•: we cannot be certain that we will be able to identify other attractive natural resource assets or will be successful in acquiring these assets at attractive prices, and this may reduce our growth from this segment;
•: the price of natural resources in which we acquire assets in the future may decline, reducing the cash flows from such natural resource assets; and
•: we may not be able to operate these natural resource assets in a profitable manner.

If we are unable to acquire other attractive natural resource assets or are unable to successfully manage or grow these assets once we acquire them, our ability to expand our cash available for distribution may be adversely affected.

Our acquisition strategy involves risks that could reduce our ability to make distributions to our unitholders.

Even if we consummate acquisitions that we believe will be accretive, they may in fact result in no increase or even a decrease in cash available for distribution to our unitholders. Any acquisition involves potential risks, including:

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

If any acquisitions we ultimately consummate do not generate expected increases in cash available for distribution to our unitholders, our ability to make such distributions will be reduced.

Extensive environmental laws and regulations affect coal consumers, which has corresponding effects on the demand for our coal. A reduction in demand for our coal could adversely affect our results of operations 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 have affected demand and prices for our higher sulfur coal. Please read "Business—Regulation and Laws."

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

Recent scientific studies have suggested that emissions of certain gases, commonly referred to as "greenhouse gases" and including carbon dioxide and methane, may be contributing to warming of the Earth's atmosphere. In response to such studies, the U.S. Congress is actively considering legislation to reduce emissions of greenhouse gases. Many states have already taken legal measures to reduce emissions of greenhouse gases, primarily through the development of regional greenhouse gas cap-and-trade programs. Also, as a result of the U.S. Supreme Court's decision on April 2, 2007 in Massachusetts, et al. v. EPA, the U.S. Environmental Protection Agency ("EPA") may be required to regulate greenhouse gas emissions from mobile sources (e.g., cars and trucks) under the federal Clean Air Act ("CAA") even if Congress does not adopt new legislation specifically addressing emissions of greenhouse gases. The Court's holding in Massachusetts that greenhouse gases fall under CAA's definition of "air pollutant" may also result in future regulation of greenhouse gas emissions from stationary sources under certain CAA programs.

The permitting of new coal-fired power plants has also recently been contested by state regulators and environmental organizations for concerns related to greenhouse gas emissions from the new plants. In October 2007, state regulators in Kansas became the first to deny an air emissions construction permit for a new coal-fired power plant based on the plant's projected emissions of carbon dioxide. Other state regulatory authorities have also rejected the construction of new coal-fired power plants based on the uncertainty surrounding the potential costs associated with greenhouse gas emissions from these plants under future laws limiting the emissions of carbon dioxide. In addition, several permits issued to new coal-fired power plants without limits on greenhouse gas emissions have been appealed to EPA's Environmental Appeals Board.

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

Federal and state laws require bonds to secure our obligations related to the statutory requirement that we reclaim mined property. Our inability to acquire or failure to maintain, obtain or renew these surety bonds could have an adverse effect on our ability to produce coal, which could adversely affect our results of operations and our ability to make distributions 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 "reclaim") and to satisfy other miscellaneous obligations. The failure to maintain or the inability to acquire sufficient surety bonds, as required by state and federal laws, could subject us

to fines and penalties as well as the loss of our mining permits. Such failure could result from a variety of factors, including:

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

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

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

We sell a material portion of our coal under supply contracts. As of December 31, 2007, we had sales commitments for 84%, 43% and 16% of our estimated coal production of approximately 8.6 million tons, 8.5 million tons and 9.3 million tons for the years ending December 31, 2008, 2009 and 2010, respectively. When our current contracts with customers expire, our customers may decide not to extend or enter into new long-term contracts. In the absence of long-term contracts, our customers may decide to purchase fewer tons of coal than in the past or on different terms, including different pricing terms. Our current long-term contracts could be renegotiated on terms less favorable to us. If a substantial portion of our supply contracts terminate and we are unable to successfully renegotiate or replace these contracts on comparable terms, then our results of operations and cash available for distribution to our unitholders could be adversely affected. For additional information relating to these contracts, please read "Business—Customers—Coal Supply Contracts."

Reduced coal consumption by North American electric power generators could result in lower prices for our coal which could adversely affect our results of operations and cash available for distribution to our unitholders.

Steam coal accounted for 97% of our coal sales volume for the year ended December 31, 2007. The majority of our sales of steam coal for the year ended December 31, 2007 were to electric utilities and affiliates. According to the U.S. Department of Energy's Energy Information Administration ("EIA"), domestic electric power generation accounted for 88% of all U.S. coal consumption for 2006. The amount of coal consumed for U.S. electric power generation is affected primarily by the overall demand for electricity, the location, availability, quality and price of competing fuels for power such as natural gas, nuclear, fuel oil and alternative energy sources such as hydroelectric power, technological developments, and environmental and other governmental regulations.

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

Overall economic activity and the associated demands for power by industrial users can have significant effects on overall electricity demand. Any downward pressure on coal prices, whether due to increased use of alternative energy sources, changes in weather patterns, decreases in overall demand or otherwise could adversely affect our results of operations 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 reopener" and other similar provisions in long-term supply agreements may reduce the protection from short-term coal price volatility traditionally provided by such contracts. As of March 31, 2008, two of our long-term coal supply contracts (those with terms longer than one year), which together account for sales of approximately 20% of our estimated annual coal production through 2010, contained provisions that allow for the purchase price to be renegotiated at periodic intervals. This price reopener provision requires the parties to agree on a new price. Failure of the parties to agree on a price under a price reopener provision can lead to termination of the contract. Any adjustment or renegotiations leading to a significantly lower contract price could adversely affect our results of operations. Accordingly, long-term coal supply contracts may provide only limited protection during adverse market conditions.

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

We depend on a few customers for a significant portion of our revenues, the loss of any of which would adversely affect our results of operations and cash available for distribution to our unitholders.

We derived 94% of our revenues from coal sales to our ten largest customers for the year ended December 31, 2007, with our top four customers, Constellation Energy Commodities Group Inc., American Electric Power Company Inc., Progress Energy Inc. and Duke Energy Corp. accounting for 72% of our revenues for that period and no other customer accounting for more than 10% of our revenues for that period. As of March 31, 2008, we had over 40 coal supply agreements with those ten customers that expire at various times through 2010. Negotiations to extend existing agreements or enter into new long-term agreements with those and other customers may not be successful, and those customers may not continue to purchase coal from us under long-term coal supply agreements, or at all. If any of these customers were to significantly reduce their purchases of coal from us, or if we were unable to sell coal to them on terms as favorable to us as the terms under our current agreements, our results of operation and our ability to make distributions to our unitholders could be adversely affected.

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

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

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

We at times utilize contractors to operate certain of our mines. For the year ended December 31, 2007, 17% of our coal production was from contractor-operated mines. Disruption in our supply of contractor-produced coal and outside vendors could temporarily impair our ability to fill our customers' orders or require us to pay higher prices in order to obtain the required coal from other sources.

Operational difficulties at contractor-operated mines, changes in demand for contract miners from other coal producers and other factors beyond our control could affect the availability, pricing and quality of coal produced by contractors for us. Any increase in the prices we pay for contractor-produced coal could increase our costs and therefore adversely affect our results of operations and our ability to make distributions to our unitholders.

Our results of operations and our cash available for distribution to our unitholders could suffer if our customers reduce or suspend their coal purchases.

Interruption in the purchases by or operations of our principal customers could significantly affect our revenues and profitability. Unscheduled maintenance outages at our customers' power plants and unseasonably moderate weather are examples of conditions that might cause our customers to reduce their purchases. Our mines are dedicated to supplying customers located adjacent to or near the mines, and these mines may have difficulty identifying alternative purchasers of their coal if their existing customers suspend or terminate their purchases.

Disputes relating to our coal supply agreements could adversely affect our results of operations and our cash available for distribution to our unitholders.

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

Changes in the export and import markets for coal products could affect the demand for our coal, our results of operations and our cash available for distribution to our unitholders.

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

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

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

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

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

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

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

We conduct a significant part of our mining operations on properties that we lease. A title defect or the loss of any lease could adversely affect our ability to mine the associated reserves. Title to most of our owned properties and leasehold interests in our leased properties and associated mineral rights is not usually verified until we make a commitment to develop a property, which may not occur until after we have obtained necessary permits and completed exploration of the property. In some cases, we rely on title information or representations and warranties provided by our grantors or lessors, as the case may be. Our right to mine some reserves would be adversely affected if defects in title or boundaries exist or if a lease expires. Any challenge to our title or interest could delay the exploration and development of the property and could ultimately result in the loss of some or all of our interest in the property. Mining operations from time to time may rely on a lease that we are unable to renew on terms at least as favorable, if at all. In such event, we may have to close down or significantly alter the sequence of such mining operations or incur additional costs to obtain or renew such leases, which could adversely affect our future coal production. If we mine on property that we do not control, we could incur liability for such mining. Neither the Wexford Principals nor the Wexford Funds will indemnify us for losses attributable to title defects in the properties that we own or lease.

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

Currently, none of our employees are represented under collective bargaining agreements. However, we cannot assure you that all of our work force will remain union-free in the future. If some or all of our currently union-free work force were to become unionized, it could adversely affect our productivity and increase the risk of work stoppages at our mines. In addition, even if we remain union-free, our operations may still be adversely affected by work stoppages at unionized companies.

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

We depend on the services of our senior management team and other key personnel. The loss of the services of any member of senior management or key employee could have an adverse effect on our business 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 ("SMCRA") and counterpart state laws and regulations establish operational, reclamation and closure standards for all aspects of surface mining as well as most aspects of deep mining. Estimates of our total reclamation and mine closing liabilities are based upon permit requirements and our engineering expertise related to these requirements. The estimate of ultimate reclamation liability is reviewed both periodically by our management and annually by independent third-party engineers. The estimated liability can change significantly if actual costs vary from assumptions or if governmental regulations change significantly. Neither the Wexford Principals nor the Wexford Funds will indemnify us against environmental liabilities associated with the assets to be contributed to us occurring before the consummation of this offering.

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

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

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

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

Our limestone mining is dependent on our coal mining.

Our current limestone mining is incidental to the coal mining process at our Sands Hill mining complex in southern Ohio, and we mine limestone and sell it as aggregate to various construction companies and road builders that are located in close proximity to our Sands Hill mining complex. If we cease our coal mining process at our Sands Hill mining complex, we will cease our limestone mining at the mining complex as well.

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

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

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

After giving effect to this offering and the related transactions, we estimate that our pro forma total debt as of December 31, 2007 would have been approximately $17.0 million. Following this offering, we will continue to have the ability to incur additional debt. Our level of indebtedness could have important consequences to us, including the following:

•: our ability to obtain additional financing, if necessary, for working capital, capital expenditures, acquisitions or other purposes may be impaired or such financing may not be available on favorable terms;
•: covenants contained in our existing and future credit and debt arrangements will require us to meet financial tests that may affect our flexibility in planning for and reacting to changes in our business, including possible acquisition opportunities;
•: we will need a portion of our cash flow to make principal and interest payments on our indebtedness, reducing the funds that would otherwise be available for operations, future business opportunities and distributions to unitholders;
•: our debt level will make us more vulnerable than our competitors with less debt to competitive pressures or a downturn in our business or the economy generally; and
•: our debt level may limit our flexibility in responding to changing business and economic conditions.

Our ability to service our indebtedness will depend upon, among other things, our future financial and operating performance, which will be affected by prevailing economic conditions and financial, business, regulatory and other factors, some of which are beyond our control. If our operating results are not sufficient to service our current or future indebtedness, we will be forced to take actions such as reducing distributions, reducing or delaying our business activities, acquisitions, investments and/or capital expenditures, selling assets, restructuring or refinancing our indebtedness, or seeking additional equity capital or bankruptcy protection. We may not be able to effect any of these remedies on satisfactory terms, or at all.

Our credit agreement contains operating and financial restrictions that may restrict our business and financing activities.

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

•: incur additional indebtedness or guarantee other indebtedness;
•: grant liens;
•: make certain loans or investments;
•: dispose of assets outside the ordinary course of business, including the issuance and sale of capital stock of our subsidiaries;
•: change the line of business conducted by us or our subsidiaries;

•: enter into a merger, consolidation or make acquisitions; or
•: make distributions if an event of default occurs.

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

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

Restrictions in our credit agreement could limit our ability to pay distributions upon the occurrence of certain events.

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:

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

Any subsequent refinancing of our current debt or any new debt could have similar restrictions. For more information regarding our credit agreement, please read "Management's Discussion and Analysis of Financial Condition and Results of Operations—Liquidity and Capital Resources—Credit Facility."

We can borrow money under our revolving credit facility to pay distributions, which would reduce the amount of credit available to operate our business.

Our partnership agreement allows us to make working capital borrowings under our revolving credit facility to pay distributions. Accordingly, we can make distributions on all our units even though cash generated by our operations may not be sufficient to pay such distributions. We expect that we will be required to reduce our borrowings to zero under the new $15.0 million sub-facility of our revolving credit facility that is expected to be available to pay the minimum quarterly distribution for a period of at least 15 consecutive days once each twelve-month period. For more information, please read

"Management's Discussion and Analysis of Financial Condition and Results of Operations—Liquidity and Capital Resources—Credit Facility."

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

At December 31, 2007, we had $18.4 million of letters of credit in place, of which $15.0 million served as collateral for reclamation surety bonds and $3.4 million secured miscellaneous obligations. Our credit agreement provides for a $200.0 million working capital revolving credit facility, of which up to $50.0 million may be used for letters of credit. If we do not maintain sufficient borrowing capacity under our revolving credit facility for additional letters of credit, we may be unable to obtain or renew surety bonds required for our mining operations.

Risks Inherent in an Investment in Us

Our partnership agreement limits our general partner's fiduciary duties to unitholders and restricts the remedies available to unitholders for actions taken by our general partner that might otherwise constitute breaches of fiduciary duty.

Fiduciary duties owed to unitholders by our general partner are prescribed by law and the partnership agreement. The Delaware Revised Uniform Limited Partnership Act (the "Delaware Act") provides that Delaware limited partnerships may, in their partnership agreements, restrict the fiduciary duties owed by the general partner to limited partners and the partnership. Our partnership agreement contains provisions that reduce the standards to which our general partner would otherwise be held by state fiduciary duty law. For example, our partnership agreement:

•: limits the liability and reduces the fiduciary duties of our general partner, while also restricting the remedies available to our unitholders for actions that, without these limitations, might constitute breaches of fiduciary duty. As a result of purchasing common units, unitholders consent to some actions and conflicts of interest that might otherwise constitute a breach of fiduciary or other duties under applicable state law;
•: permits our general partner to make a number of decisions in its individual capacity, as opposed to in its capacity as our general partner. This entitles our general partner to consider only the interests and factors that it desires, and it has no duty or obligation to give any consideration to any interest of, or factors affecting, us, our affiliates or any limited partner. Examples include the exercise of its limited call right, its voting rights with respect to the units it owns, its registration rights and its determination whether or not to consent to any merger or consolidation of the partnership;
•: provides that our general partner shall not have any liability to us or our unitholders for decisions made in its capacity as general partner so long as it acted in good faith, meaning it believed that the decision was in the best interests of the partnership;
•: generally provides that affiliated transactions and resolutions of conflicts of interest not approved by the conflicts committee of the board of directors of our general partner and not involving a vote of unitholders must be on terms no less favorable to us than those generally being provided to or available from unrelated third parties or be "fair and reasonable" to us and that, in determining whether a transaction or resolution is "fair and reasonable," our general partner may consider the totality of the relationships between the parties involved, including other transactions that may be particularly advantageous or beneficial to us; and

•: provides that our general partner and its officers and directors will not be liable for monetary damages to us, our limited partners or assignees for any acts or omissions unless there has been a final and non-appealable judgment entered by a court of competent jurisdiction determining that our general partner or those other persons acted in bad faith or engaged in fraud or willful misconduct.

By purchasing a common unit, a common unitholder will become bound by the provisions of the partnership agreement, including the provisions described above. Please read "Description of the Common Units—Transfer of Common Units."

Our general partner and its affiliates have conflicts of interest, and their limited fiduciary duties to unitholders may permit them to favor their own interests to the detriment of our unitholders.

Following the offering, Wexford Funds will own an 84.6% limited partner interest in us (or an 82.9% limited partner interest if the underwriters exercise their option to purchase additional common units in full), and the Wexford Principals will own and control our general partner. Although our general partner has certain fiduciary duties to manage us in a manner beneficial to us and our unitholders, the executive officers and directors of our general partner have a fiduciary duty to manage our general partner in a manner beneficial to its owners. Furthermore, since certain executive officers and directors of our general partner are executive officers or directors of affiliates of our general partner, conflicts of interest may arise between the Wexford Principals, Wexford Funds and their affiliates, including our general partner, on the one hand, and us and our unitholders, on the other hand. As a result of these conflicts, our general partner may favor its own interests and the interests of its affiliates over the interests of our unitholders. Please read "—Our partnership agreement limits our general partner's fiduciary duties to unitholders and restricts the remedies available to unitholders for actions taken by our general partner that might otherwise constitute breaches of fiduciary duty." The risk to unitholders due to such conflicts may arise because of the following factors, among others:

•: our general partner is allowed to take into account the interests of parties other than us, such as the Wexford Principals, in resolving conflicts of interest, which has the effect of limiting its fiduciary duty to our unitholders;
•: neither our partnership agreement nor any other agreement requires owners of our general partner to pursue a business strategy that favors us. Executive officers and directors of our general partner's owners have a fiduciary duty to make these decisions in the best interest of their owners, which may be contrary to our interests;
•: some executive officers of our general partner who will provide services to us will devote time to affiliates of our general partner and may be compensated for services rendered to such affiliates;
•: our general partner determines the amount and timing of asset purchases and sales, capital expenditures, borrowings, issuances of additional partnership securities and reserves, each of which can affect the amount of cash that is available for distribution to our unitholders;
•: our general partner determines whether a capital expenditure is a maintenance capital expenditure, which reduces operating surplus, or an expansion capital expenditure, which does not, and that determination can affect the amount of cash that is distributed to our unitholders and the ability of the subordinated units to convert to common units;
•: in some instances, our general partner may cause us to borrow funds in order to permit the payment of cash distributions, even if the purpose or effect of the borrowing is to make a distribution on the subordinated units, to make incentive distributions or to accelerate the expiration of the subordination periods;

•: our general partner determines which costs incurred by it and its affiliates are reimbursable by us, including those reimbursable to Wexford;
•: our partnership agreement does not restrict our general partner from causing us to pay it or its affiliates for any services rendered on terms that are fair and reasonable to us or entering into additional contractual arrangements with any of these entities on our behalf;
•: our general partner intends to limit its liability regarding our contractual and other obligations;
•: our general partner may exercise its limited right to call and purchase common units if it and its affiliates own more than 90% of the common units (if our general partner and its affiliates reduce their ownership percentage to below 50% of the outstanding common units, the ownership threshold to exercise the limited call rights will be reduced to 80%);
•: our general partner controls the enforcement of obligations owed to us by it and its affiliates; and
•: our general partner decides whether to retain separate counsel, accountants or others to perform services for us.

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, and affiliates of our general partner may compete with us."

Our sponsor, Wexford, 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, 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 currently holds substantial interests in other companies in the energy and natural resources sectors. Wexford, through its investment funds and managed accounts, makes investments and purchases entities in the coal and oil and natural gas sectors. These investments and acquisitions may include entities or assets that we would have been interested in acquiring. Therefore, Wexford may compete with us for investment opportunities and Wexford may own an interest in entities that compete with us.

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. 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."

Unitholders have limited voting rights and are not entitled to elect our general partner or its directors or initially to remove our general partner without its consent.

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 to elect our general partner or its board of directors on an annual or other continuing basis. The board of directors of our general partner is chosen entirely by its members and not by our unitholders. Furthermore, if our unitholders are dissatisfied with the performance of our general partner, they will have limited ability to remove our general partner.

Unitholders will be unable initially to remove our general partner without its consent because affiliates of our general partner will own sufficient units upon the consummation of this offering to be able to prevent removal of our general partner. 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, affiliates of our general partner will own 86.4% of our common and subordinated units (or 84.6% 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 units held by our general partner and its affiliates are not 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. A removal of our general partner under these circumstances would adversely affect the common units by prematurely eliminating their distribution and liquidation preference over the subordinated units, which would otherwise have continued until we had met certain distribution and performance tests.

Cause is narrowly defined in our partnership agreement to mean that a court of competent jurisdiction has entered a final, non-appealable judgment finding our general partner liable for actual fraud or willful or wanton misconduct in its capacity as our general partner. Cause does not include most cases of charges of poor management of the business, so the removal of our general partner during the subordination period because of the unitholders' dissatisfaction with our general partner's performance in managing our partnership will most likely result in the termination of the subordination period. 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.

Unitholders will experience immediate and substantial dilution of $15.56 per common unit.

The assumed initial public offering price of $20.00 per common unit exceeds pro forma net tangible book value of $4.44 per common unit. Unitholders will incur immediate and substantial dilution of $15.56 per common unit. This dilution results primarily because the assets contributed to us by affiliates of our general partner are recorded at their historical cost, and not their fair value. Please read "Dilution."

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, there is no restriction in the partnership agreement on 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 choices and to control the decisions taken by the board of directors and executive officers of our general partner.

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

Upon consummation of this offering, Wexford Funds will own an aggregate of 86.4% of our common and subordinated units (or 84.6% of our common and subordinated units, if the underwriters exercise their option to purchase additional common units in full). 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 not less than the then-current market price. If our general partner and its affiliates reduce their ownership percentage to below 50% 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 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. For additional information about the limited call right, please read "The Partnership Agreement—Limited Call Right."

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

At any time, we may issue an unlimited number of limited partner interests of any type without the approval of our unitholders. Further, our partnership agreement does not prohibit the issuance of equity securities that may effectively rank senior to our common units. The issuance by us of additional common units or other equity securities of equal or senior rank will have the following effects:

•: our unitholders' proportionate ownership interest in us will decrease;
•: the amount of cash available for distribution on each unit may decrease;
•: because a lower percentage of total outstanding units will be subordinated units, the risk that a shortfall in the payment of the minimum quarterly distribution will be borne by our common unitholders will increase;
•: the relative voting strength of each previously outstanding unit may be diminished; and
•: the market price of the common units may decline.

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 who owns 20% or more of any class of units then outstanding, other than our general partner, 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. Our partnership agreement also contains provisions limiting the ability of unitholders to call meetings or to acquire information about our operations, as well as other provisions limiting the unitholders' ability to influence the manner or direction of management.

Cost reimbursements due to our general partner and its affiliates will reduce cash available for distribution to our unitholders.

Prior to making any distribution on the common units, we will reimburse our general partner and its affiliates for all expenses they incur on our behalf, which will be determined by our general partner in its sole discretion in accordance with the terms of the partnership agreement. In determining the costs and expenses allocable to us, our general partner is subject to its fiduciary duty, as modified by our partnership agreement, to the limited partners, which requires it to act in good faith. These expenses will include all costs incurred by our general partner and its affiliates in managing and operating us, including costs for rendering corporate staff and support services to us. Wexford will charge on a fully allocated cost basis for services provided to us, other than legal support which will be on an hourly basis. This fully allocated cost basis is based on the percentage of time spent by Wexford personnel on our matters and includes the compensation paid by Wexford to such persons and their allocated overhead. The allocation of compensation expense for those executive officers of our general partner who are employees of Wexford will be determined based on a good faith estimate of the value of each such executive officer's services performed on our business and affairs, subject to the approval of the audit committee of our general partner. The fully allocated basis charged by Wexford does not include a profit component. In connection with the quarterly review of our financial statements, all costs and expenses incurred by our general partner that are reimbursed by us are subject to review of the audit committee of the board of directors of our general partner on a quarterly basis. We are managed and operated by executive officers and directors of our general partner. Please read "Cash Distribution Policy and Restrictions on Distributions," "Certain Relationships and Related Party Transactions" and "Conflicts of Interest and Fiduciary Duties—Conflicts of Interest." The reimbursement of expenses and payment of fees, if any, to our general partner and its affiliates could reduce the amount of available cash to pay cash distributions to our unitholders.

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

Prior to the offering, there has been no public market for the common units. After the offering, there will be only 5,000,000 publicly traded common units (or 5,750,000 publicly traded common units, if the underwriters exercise their option to purchase additional common units in full). 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 the units has been 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:

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

•: general economic conditions;
•: the failure of securities analysts to cover our 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."

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 as a private company. We expect that complying with the rules and regulations implemented by the SEC and the NASDAQ Global Select Market will increase our legal and financial compliance costs and make activities more time-consuming and costly. For example, as a result of becoming a publicly traded partnership, we are required to have three independent directors, create additional board committees and adopt policies regarding internal controls and disclosure controls and procedures, including the preparation of reports on internal controls over financial reporting. In addition, we will incur additional costs associated with our publicly traded partnership reporting requirements.

Unitholders who fail to furnish certain information requested by our general partner or who our general partner, upon receipt of such information, determines are not eligible citizens will not be entitled to receive distributions or allocations of income or loss on their common units and their common units will be subject to redemption.

Our general partner may require each limited partner or assignee to furnish information about his nationality, citizenship or related status. If a limited partner or assignee fails to furnish information about his nationality, citizenship or other related status within 30 days after a request for the information or our general partner determines after receipt of the information that the limited partner or assignee is not an eligible citizen, the limited partner or assignee may be treated as a non-citizen assignee. In addition to other limitations on the rights of an assignee that is not a limited partner, a non-citizen assignee does not have the right to direct the voting of his units and may not receive distributions in kind upon our liquidation. Furthermore, we have the right to redeem all of the common and subordinated units of any holder that is not an eligible citizen or fails to furnish the requested information. The redemption price will be paid in cash or by delivery of a promissory note, as determined by our general partner. Please read "The Partnership Agreement—Non-Citizen Assignees; Redemption."

Our partnership agreement may be amended to enlarge the obligations of the unitholders upon the approval of the holders of at least 90% of the outstanding common units.

Our partnership agreement prohibits any amendment that may enlarge the obligations of any limited partner without its consent, unless approved by at least a majority of the type or class of limited partner interests so affected. However, this provision preventing such an amendment can be amended upon the approval of at least 90% of the outstanding common units voting together as a single class (including units owned by our general partner and its affiliates). Upon the consummation of this offering, affiliates of our general partner will own 86.4% of the outstanding common and subordinated units (or 84.6% of our common and subordinated units, if the underwriters exercise their option to purchase additional common units in full).

Unitholders may have liability to repay distributions.

Under certain circumstances, unitholders may have to repay amounts wrongfully returned or distributed to them. Under Section 17-607 of 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. Purchasers of units who become limited partners are 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.

Our general partner may mortgage, pledge or grant a security interest in all or substantially all of our assets without prior approval of our unitholders.

Our general partner may mortgage, pledge or grant a security interest in all or substantially all of our assets without prior approval of our unitholders. If our general partner secures our obligations or indebtedness by all or substantially all of our assets and if we are unable to satisfy such obligations or repay such indebtedness, the lenders could seek to foreclose on our assets. The lenders may also sell all or substantially all of our assets under such foreclosure or other realization upon those encumbrances without prior approval of our unitholders, which would adversely affect the price of our common units.

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 requested, and do not plan to request, a ruling from the 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 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.

Current law may change so as to cause us to be treated as a corporation for federal income tax purposes or otherwise subject us to entity-level taxation. 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. 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.

Our partnership agreement provides that if a law is enacted or existing law is modified or interpreted in a manner that subjects us to taxation as a corporation or otherwise subjects us to entity-level taxation for federal, state or local income tax purposes, the minimum quarterly distribution amount and the target distribution amounts may be adjusted to reflect the impact of that law on us.

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.

Unitholders will be required to pay taxes on their share of our income 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, unitholders will be required to pay any 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.

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

The present 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, members of the U.S. Congress are considering substantive changes to the existing federal income tax laws that affect certain publicly traded partnerships. Any modification to the federal income tax laws and interpretations thereof may or may not be applied retroactively. Although the currently proposed legislation would not appear to affect our tax treatment as a partnership, we are unable to predict whether any of these changes, or other proposals, will ultimately be enacted. Any such changes could negatively impact the value of an investment in our common units.

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

We have not requested a ruling from the IRS with respect to our treatment as a partnership for 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. 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.

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 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 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 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 foreign persons face unique tax issues from owning our common units that may result in adverse tax consequences to them.

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 Colorado, Illinois, Kentucky, Ohio, Pennsylvania and West Virginia. Most of these states also impose an income tax on corporations and other entities. In addition, each of these states also imposes 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.

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.

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.

Because we cannot match transferors and transferees of common units and because of other reasons, 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. 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 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 use of this proration method may not be permitted under existing Treasury Regulations, and, accordingly, our counsel is unable to opine as to the validity of this method. If the IRS were to challenge this method or new Treasury regulations were issued, we may be required to change the 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."

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 modify any applicable brokerage account agreements to prohibit their brokers from loaning their units.

We will adopt certain valuation methodologies 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 terminated our partnership 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. Our termination would, among other things, result in the closing of our taxable year for all unitholders, which would result in us filing two tax returns (and our unitholders could receive two Schedules K-1) for one 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. Our termination currently would not affect our classification as a partnership for federal income tax purposes, but instead, we would be treated as a new partnership for tax purposes. If treated as a new partnership, we must make new tax elections and could be subject to penalties if we are unable to determine that a termination occurred. Please read "Material Tax Consequences—Disposition of Common Units—Constructive Termination" for a discussion of the consequences of our termination for federal income tax purposes.

USE OF PROCEEDS

Based on an assumed initial offering price of $20.00 per common unit, we expect to receive net proceeds of approximately $92.0 million from the sale of 5,000,000 common units offered by this prospectus, after deducting the estimated underwriting discount and offering expenses payable by us.

We intend to use the net proceeds from this offering to repay approximately $67.0 million of outstanding indebtedness under our credit facility, a portion of which was used to finance the acquisitions of the Sands Hill and Deane mining complexes. The remainder of approximately $25.0 million will be distributed to Rhino Energy Holdings LLC as reimbursement for capital expenditures (expenditures that were capitalized for federal income tax purposes) incurred within the prior 24 months by Rhino Energy LLC with respect to the assets to be contributed to us upon the closing of this offering. Please read "Business—Our History" and "Management's Discussion and Analysis of Financial Condition and Results of Operations—Liquidity and Capital Resources—Capital Expenditures" for information on these capital expenditures.

Our credit facility bears interest at either (1) LIBOR plus 1.25% to 1.75% per annum depending on our leverage ratio or (2) a base rate that is the higher of the prime rate or the federal funds rate plus 0.50%. We incur letter of credit fees equal to the then applicable spread above LIBOR on the undrawn face amount of standby letters of credit issued and a 15 basis point fronting fee payable to the administrative agent on the aggregate face amount of such letters of credit. In addition, we incur a commitment fee on the unused portion of the credit facility at a rate of 0.25% per annum based on the unused portion of the facility. The credit facility will mature in 2013. Please read "Management's Discussion and Analysis of Financial Condition and Results of Operations—Liquidity and Capital Resources—Credit Facility."

The net proceeds from any exercise of the underwriters' option to purchase additional common units may be distributed to Rhino Energy Holdings LLC or used for general partnership purposes, including the repayment of indebtedness.

An increase or decrease in the initial public offering price by $1.00 per common unit would cause the net proceeds from this offering, after deducting the underwriting discount and offering expenses payable by us, to increase or decrease, respectively, by approximately $4.7 million (or approximately $5.3 million if the underwriters exercise their option to purchase additional common units in full).

CAPITALIZATION

The following table shows our capitalization as of December 31, 2007:

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

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

This table does not reflect the issuance of up to an additional 750,000 common units that we may sell to the underwriters upon exercise of their option to purchase additional common units, the net proceeds of which may be distributed to Rhino Energy Holdings LLC or used for general partnership purposes, including the repayment of indebtedness.

					As of December 31, 2007
					Actual		Pro Forma
					(in thousands)
Debt:
	Credit facility				$	69,000.0	$	2,000.0
	Other debt					14,953.7		14,953.7

		Total debt				83,953.7		16,953.7
Members'/partners' equity:
	Rhino Energy LLC					117,840.5		—
	Rhino Resource Partners, L.P.:
		Held by public:
			Common units(1)			—		22,218.3
		Held by the Wexford Principals and Wexford Funds:
			Common units			—		124,090.0
			Subordinated units			—		16,625.9
			General partner interest			—		3,325.2

			Accumulated other comprehensive income			—		588.4
			Total members'/partners' equity			117,840.5		166,847.8

				Total capitalization(1)	$	201,794.2	$	183,801.5

(1): An increase or decrease in the initial public offering price by $1.00 per common unit would cause the net proceeds from this offering, after deducting underwriting discount offering expenses payable by us, to increase or decrease, respectively, by approximately $4.7 million (or approximately $5.3 million, if the underwriters exercise their option to purchase additional common units in full).

DILUTION

Dilution is the amount by which the offering price will exceed the net tangible book value per unit after the offering. Assuming an initial public offering price of $20.00 per common unit, on a pro forma basis as of December 31, 2007, after giving effect to the offering of common units and the related transactions, our net tangible book value was approximately $165.9 million, or $4.44 per common unit. The pro forma net book value excludes $0.9 million of deferred financing costs. Purchasers of 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
	Net tangible book value per common unit before the offering(1)	$	3.61
	Increase in net tangible book value per common unit attributable to purchasers in the offering		0.83

Less: Pro forma net tangible book value per common unit after the offering(2)					4.44

Immediate dilution in net tangible book value per common unit to purchasers in the offering(3)				$	15.56

(1): Determined by dividing the net tangible book value of the contributed assets and liabilities by the number of units (27,925,200 common units, 3,741,500 subordinated units and the 2% general partner interest represented by 748,300 general partner unit equivalents) to be issued to our general partner and its affiliates for their contribution of assets and liabilities to us. The number of general partner unit equivalents 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%) by our general partner's 2% 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 (32,925,200 common units, 3,741,500 subordinated units and the 2% general partner interest represented by 748,300 general partner unit equivalents) to be outstanding after the offering.
(3): If the initial public offering price were to increase or decrease by $1.00 per common unit, immediate dilution in net tangible book value per common unit would increase or decrease by $1.00.

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

	Units			Total Consideration
	Number	Percent		Amount		Percent
General partner and its affiliates(1)(2)	32,415,000	86.6	%	$	65,900,000	39.7	%
New investors	5,000,000	13.4	%		100,000,000	60.3	%

Total	37,415,000	100.0	%	$	165,900,000	100.0	%

(1): Upon the consummation of the transactions contemplated by this prospectus, our general partner and its affiliates will own 27,925,200 common units, 3,741,500 subordinated units and a 2% general partner interest represented by 748,300 general partner unit equivalents.
(2): The assets contributed by Rhino Energy Holdings LLC will be recorded at historical cost. Pro forma book value of the consideration provided by Rhino Energy Holdings LLC, as of December 31, 2007, after giving effect to the distribution of approximately $25.0 million to Rhino Energy Holdings LLC, would have been approximately $65.9 million.

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 historical consolidated financial statements as of December 31, 2006 and 2007 and for the year ended March 31, 2006, the nine months ended December 31, 2006 and the year ended December 31, 2007 of Rhino Energy LLC and our unaudited pro forma consolidated financial statements as of and for the year ended December 31, 2007, included elsewhere in this prospectus.

General

Rationale for Our Cash Distribution Policy

Our cash distribution policy reflects a basic judgment that our unitholders will be better served by distributing our available cash (after deducting expenses, including estimated maintenance and replacement capital expenditures, and cash reserves) rather than retaining it, because, among other reasons, we believe we will generally finance any expansion capital expenditures from external financing sources. Because we are not subject to an entity-level federal income tax, we have more cash to distribute to you than would be the case were we subject to federal tax. Our cash distribution policy is consistent with the terms of our partnership agreement, which requires that we distribute all of our available cash (after deducting expenses, including estimated maintenance and replacement capital expenditures, and reserves) quarterly.

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 distribution policy is subject to restrictions on cash distributions under our credit agreement. Specifically, 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 Facility." Should we be unable to satisfy these restrictions included in our credit agreement or if we are otherwise in default under our credit agreement, we would be prohibited from making cash distributions to you notwithstanding our stated cash distribution policy.
•: The board of directors of 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 those reserves could result in a reduction in cash distributions to you from levels we currently anticipate pursuant to our stated cash distribution policy.
•: 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. Although during the subordination period, with certain exceptions, our partnership agreement may not be amended without the approval of unaffiliated common unitholders, our partnership agreement can be amended with the approval of a majority of the outstanding common units after the subordination period has ended. At the closing of this offering, Wexford Funds will own 84.8% of the outstanding common units and 100% of the outstanding subordinated units. Certain executive officers and directors of our general partner are Wexford Principals.

•: 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 to you 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 reduced revenues from sales of our products or increases in our 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 constitute a return of capital and will result in a reduction in the minimum quarterly distribution and the target distribution levels. Please read "How We Make Distributions—Adjustments to the Minimum Quarterly Distribution and Target 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.

We have a limited operating history upon which to rely with respect to whether we will have sufficient cash available for distributions to allow us to pay the minimum quarterly distribution on our common and subordinated units. While we believe, based on our financial forecast and related assumptions, that we will have sufficient cash to enable us to pay the full minimum quarterly distribution on all of our common and subordinated units for the twelve months ending June 30, 2009, our pro forma cash available for distributions generated during the year ended December 31, 2007 would have been sufficient to allow us to pay the minimum quarterly distribution on only 82.7% of our common units and on none of our subordinated units (or on 80.8% of our common units and on none of our subordinated units, if the underwriters exercise their option to purchase additional common units in full). This represents 72.7% of the total distributions payable to all unitholders and the general partner (or 71.3%, if the underwriters exercise their option to purchase additional common units in full).

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

We will 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 our asset base. In addition, because we will 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 in connection with any maintenance and replacement expenditures 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, which in turn may impact the available cash that we have to distribute on each unit. 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.

Minimum Quarterly Distribution Rate

Upon the consummation of this offering, the board of directors of our general partner will adopt a policy pursuant to which we will pay a minimum quarterly distribution of $0.375 per unit for each complete quarter, or $1.50 per unit on an annualized basis, to be paid within 45 days after the end of each quarter. We will adjust our first distribution for the period from the closing of this offering through June 30, 2008 based on the actual length of the period. Our ability to make cash distributions at the minimum quarterly distribution rate pursuant to this 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 and subordinated units and the 2% general partner interest to be outstanding immediately after this offering for one quarter and for four quarters is summarized in the table below:

		Number of Units	One Quarter		Four Quarters
Assuming no exercise of the underwriters' option:
Common units		32,925,200	$	12,346,950	$	49,387,800
Subordinated units		3,741,500		1,403,063		5,612,250
2% general partner interest(1)		748,300		280,613		1,122,450

	Total	37,415,000	$	14,030,626	$	56,122,500

Assuming full exercise of the underwriters' option:
Common units		33,675,200	$	12,628,200	$	50,512,800
Subordinated units		3,741,500		1,403,063		5,612,250
2% general partner interest(1)		763,606		286,352		1,145,409

	Total	38,180,306	$	14,317,615	$	57,270,459

(1): The number of general partner unit equivalents 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%) by our general partner's 2% general partner interest.

As of the date of this offering, our general partner will be entitled to 2% of all distributions that we make prior to our liquidation. Our general partner's initial 2% 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% general partner interest. We will also issue to our general partner the incentive distribution rights, which entitle the holder to increasing percentages, up to a maximum of 10%, of the cash we distribute in excess of $0.425 per unit per quarter, in connection with our initial public offering.

During the subordination period, before we make any quarterly distributions to our subordinated unitholders, our common unitholders are entitled to receive payment of the full minimum quarterly distribution plus any arrearages in distributions from prior quarters. Please read "How We Make 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 our general partner determines is necessary or appropriate 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 upcoming 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 our partnership agreement, 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 "How We Make Cash Distributions."

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. During the subordination period, our partnership agreement may be amended with the approval of our general partner and holders of a majority of our outstanding common units.

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 for the period from the closing of this offering through June 30, 2008 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 the 2% general partner interest for the twelve months ending June 30, 2009. We present a table, consisting of pro forma and forecasted results of operations and cash available for distribution for the year ended December 31, 2007 and the twelve months ending June 30, 2009. In the table, 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, 2007 based on our pro forma consolidated statement of operations included elsewhere in this prospectus and our forecasted results of operations and the amount of cash available for distribution for the twelve months ending June 30, 2009 and the significant assumptions upon which this forecast is based.

Our unaudited pro forma consolidated financial statements for the year ended December 31, 2007 reflect the following transactions:

•: the distribution by Rhino Energy LLC of its ownership interests in CAM-Colorado LLC, an entity that owns certain properties located in Colorado that will not be retained by us, to NR Energy LLC, an entity owned by certain Wexford Funds;
•: the contribution by Rhino Energy Holdings LLC, which is also owned by certain Wexford Funds, of 100% of the ownership interests in Rhino Energy LLC to us;
•: the issuance by us to Rhino Energy Holdings LLC of an aggregate of 27,925,200 common units and 3,741,500 subordinated units, representing a combined 84.6% limited partner interest in us;
•: the issuance by us to our general partner of the incentive distribution rights, which entitle the holder to increasing percentages, up to a maximum of 10%, of the cash we distribute in excess

of $0.425 per unit per quarter. Our general partner will maintain its 2% general partner interest in us;

•: the issuance by us to the public of 5,000,000 common units, representing a 13.4% limited partner interest in us;
•: the repayment of $67.0 million indebtedness under Rhino Energy LLC's current credit facility and the distribution of $25.0 million of the proceeds from the offering to Rhino Energy Holdings LLC as reimbursement for capital expenditures (expenditures that were capitalized for federal income tax purposes) incurred within the prior 24 months by Rhino Energy LLC with respect to the assets to be contributed to us upon the closing of this offering; and
•: the payment of the estimated underwriting discount and offering expenses of $8.0 million.

The unaudited pro forma consolidated financial statements are based on the audited historical consolidated financial statements of Rhino Energy LLC included elsewhere in this prospectus, as adjusted to illustrate the estimated pro forma effects of the transactions described above. The unaudited pro forma consolidated financial statements should be read together with "Selected Historical and Pro Forma Consolidated Financial and Operating Data," "Management's Discussion and Analysis of Financial Condition and Results of Operations," the historical consolidated financial statements of Rhino Energy LLC and the notes to those statements included elsewhere in this prospectus.

If we had completed the transactions contemplated in this prospectus on January 1, 2007 as a publicly traded partnership, pro forma cash available for distribution generated during the year ended December 31, 2007 would have been approximately $40.8 million. This amount would have been sufficient to pay the minimum quarterly distribution on only 82.7% of our common units and on none of our subordinated units at the minimum quarterly distribution rate of $0.375 per unit each quarter (or $1.50 per unit on an annualized basis) (or on 80.8% of our common units and on none of our subordinated units, if the underwriters exercise their option to purchase additional common units in full). This represents 72.7% of the total distributions payable to all unitholders and the general partner (or 71.3%, if the underwriters exercise their option to purchase additional common units in full).

The following table also sets forth our calculation of forecasted cash available for distribution to our unitholders and general partner. We forecast that our cash available for distribution generated during the twelve months ending June 30, 2009 will be approximately $95.2 million. This amount would be sufficient to pay the full minimum quarterly distribution of $0.375 per unit on all of our common units and subordinated units for the four quarters ending June 30, 2009.

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 outstanding common and subordinated units for each quarter in the twelve months ending June 30, 2009 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.

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 June 30, 2009. 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 $0.375 per unit each quarter (or $1.50 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 its preparation, 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 forecast set forth below to present the estimated 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 fact and should not be relied upon as being necessarily indicative of future results, and readers of this prospectus are cautioned not to place undue reliance on the forecast.

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 intend to update or otherwise revise the forecast to reflect circumstances existing since its preparation or to reflect the occurrence of unanticipated events, even in the event that any or all of the underlying assumptions are shown to be in error. Furthermore, we do not intend to update or revise the forecast to reflect changes in general economic or industry conditions.

		Pro Forma			Forecasted(1)
		Year Ended December 31, 2007			Twelve Months Ending June 30, 2009
		(in thousands, except average coal price per ton)
Operating data:
Total coal produced in tons			7,057			8,572
Coal sold from inventory in tons			135			35
Coal purchased in tons			967			—

Total coal sales in tons			8,159			8,607
Coal sales in tons—sold/committed(2)			8,159			7,261
Average steam coal sales price per ton—sold/committed(2)		$	47.74		$	50.72
Average metallurgical coal sales price per ton—sold/committed(2)		$	64.05		$	72.30
Coal sales revenue—sold/committed(2)		$	394,079		$	381,835
Coal sales in tons—uncommitted			n/a			1,346
Average steam coal sales price per ton—uncommitted			n/a		$	67.03
Average metallurgical coal sales price per ton—uncommitted			n/a		$	124.19
Coal sales revenue—uncommitted			n/a		$	117,564
Other revenues(3)		$	9,364		$	23,062
Total revenues		$	403,443		$	522,461
Costs and expenses:
	Cost of operations (exclusive of depreciation, depletion and amortization shown separately below)		318,531			365,372
	Freight and handling		4,021			8,512
	Depreciation, depletion and amortization		30,750			38,834
	Selling, general and administrative		15,369			15,665
	Incremental selling, general and administrative		—			3,000
	(Gain) loss on retirement of advance royalties		(115	)		—
	(Gain) loss on sale of assets		(944	)		—

	Total costs and expenses		367,612			431,383

Income from operations			35,831			91,078
Interest and other income (expense):
	Interest expense		(1,801	)		(1,714	)
	Interest income		317			—
	Other—net		—			—
	Income tax benefit		126			—

Net income		$	34,473		$	89,364

Plus:
	Depreciation, depletion and amortization		30,750			38,834
	Interest expense		1,801			1,714
	Income tax benefit		(126	)		—

EBITDA(4)		$	66,898		$	129,912
Less:
	Interest expense		(1,801	)		(1,714	)
	Maintenance and replacement capital expenditures(5)		(19,047	)		(33,000	)
	Expansion capital expenditures		(30,361	)		(14,234	)
Plus:
	Borrowings for expansion capital expenditures		25,139			14,234

Cash available for distribution		$	40,828		$	95,198

		Pro Forma			Forecasted(1)
		Year Ended December 31, 2007			Twelve Months Ending June 30, 2009
		(in thousands, except per unit data and %)
Cash available for distribution		$	40,828		$	95,198

Expected cash distributions:
Assuming no exercise of the underwriters' option: Annualized minimum quarterly distribution per unit		$	1.50		$	1.50
	Distributions to public common unitholders	$	7,500		$	7,500
	Distribution to Rhino Energy Holdings LLC—common units		41,888			41,888
	Distribution to Rhino Energy Holdings LLC—subordinated units		5,612			5,612
	Distribution to the general partner		1,122			1,122

	Total distributions to unitholders and the general partner(6)	$	56,122		$	56,122

Excess (shortfall)		$	(15,294	)	$	39,076

Assuming full exercise of the underwriters' option
	Annualized minimum quarterly distribution per unit	$	1.50		$	1.50
	Distributions to public common unitholders	$	8,625		$	8,625
	Distribution to Rhino Energy Holdings LLC—common units		41,888			41,888
	Distribution to Rhino Energy Holdings LLC—subordinated units		5,612			5,612
	Distribution to the general partner		1,145			1,145

	Total distributions to unitholders and the general partner(6)	$	57,270		$	57,270

Excess (shortfall)		$	(16,442	)	$	37,928

(1): The forecasted column is based on the assumptions set forth in "—Significant Forecast Assumptions" below.
(2): Represents coal sold for the year ended December 31, 2007 on a pro forma basis and coal committed for sale for the twelve months ending June 30, 2009.
(3): Other revenues consist of limestone sales, coal handling, royalties, contract mining and rental income.
(4): EBITDA is a non-GAAP financial measure, which we use in our business as it is an important supplemental measure of our performance and liquidity. EBITDA means earnings before interest, taxes, depreciation, depletion and amortization. This measure is not calculated or presented in accordance with GAAP. We explain this measure below and reconcile it to its most directly comparable financial measures calculated and presented in accordance with GAAP.

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

•: our compliance with certain financial covenants included in our debt agreements;
•: our financial performance without regard to financing methods, capital structure or income taxes;

•: our ability to generate cash sufficient to pay interest on our indebtedness and to make distributions to our partners; and
•: the viability of acquisitions and capital expenditure projects and the overall rates of return of alternative investment opportunities.

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

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

			Pro Forma			Forecasted
			Year Ended December 31, 2007			Twelve Months Ending June 30, 2009
			(in thousands)
Reconciliation of EBITDA to net income:
	Net income		$	34,473		$	89,364
	Plus:
		Depreciation, depletion and amortization		30,750			38,834
		Interest expense		1,801			1,714
		Income tax benefit		(126	)		—

	EBITDA		$	66,898		$	129,912

(5): The $33.0 million of maintenance and replacement capital expenditures for the forecasted twelve months ending June 30, 2009 represents estimated maintenance and replacement capital expenditures as defined in our partnership agreement. The $19.0 million for the year ended December 31, 2007 represents actual maintenance and replacement capital expenditures. Expansion capital expenditures for the forecast period are expected to be approximately $14.2 million. The amount of our actual maintenance and replacement 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 and replacement capital expenditures from operating surplus. To eliminate these fluctuations, our partnership agreement will require that an estimate of the maintenance and replacement capital expenditures necessary to maintain or replace our capital asset base be subtracted from operating surplus each quarter as opposed to amounts actually spent. Our initial estimated maintenance and replacement capital expenditures will be approximately $33.0 million per year. The amount of estimated maintenance and replacement 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. Please read "How We Make Cash Distributions—Definition of Operating Surplus" for a further discussion of the effects of our use of estimated maintenance and replacement capital expenditures.
(6): Represents the amount required to pay the minimum quarterly distribution to our unitholders and our general partner for four quarters based upon our minimum quarterly distribution rate of $0.375 per unit.

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 June 30, 2009. 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 June 30, 2009 will be approximately $522.5 million, as compared to approximately $403.4 million, on a pro forma basis, for the year ended December 31, 2007. Our forecast is based primarily on the following assumptions:

•: We estimate that we will produce and sell approximately 8.6 million tons of coal for the twelve months ending June 30, 2009, as compared to approximately 7.1 million tons we produced and approximately 8.2 million tons we sold for the year ended December 31, 2007, on a pro forma basis. This volume increase is primarily due to additional coal production tons from our Sands Hill mining complex located in southern Ohio that we acquired in December 2007 and the Deane mining complex located in Central Appalachia that we acquired in February 2008. We expect to produce an aggregate of approximately 1.7 million tons of coal from these two mining complexes in the forecasted period. Our Hopedale mining complex, our operation located in Northern Appalachia, is also projected to increase production by approximately 0.2 million tons of coal for the forecasted period from 2007. The additional tons produced will be offset by a decline of approximately 0.4 million tons of coal produced in our Rob Fork mining complex located in Central Appalachia. Our operation at the McClane Canyon mine located in Colorado is forecasted to remain flat. We expect the quality of coal to be produced during the forecasted period to be similar to what we produced for the year ended December 31, 2007. Our coal production could vary significantly from the foregoing assumption based on numerous factors, many of which are beyond our control.
•: We estimate that the coal revenues per ton will be $58.02 for the twelve months ending June 30, 2009, as compared to $48.30 for the year ended December 31, 2007, on a pro forma basis. This increase is primarily due to the recent increase in coal prices in the regions in which we operate. We have commitments to sell approximately 7.3 million tons, or 84% of the forecasted production, during the forecasted period. Our coal revenues per ton could vary significantly from the foregoing assumption if we are unable to deliver coal pursuant to our contracts or if a number of our customers are unable to satisfy their contractual obligations.

Cost of Operations. We forecast our cost of operations will be $365.4 million for the twelve months ending June 30, 2009, as compared to $318.5 million for the year ended December 31, 2007, on a pro forma basis. Cost of operations primarily includes the cost of labor and benefits, operating supplies, equipment maintenance, royalties, taxes and transportation costs. The increase in cost of operations is attributable primarily to increased production. We forecast that tons of coal produced and sold will increase to approximately 8.6 million tons for the twelve months ending June 30, 2009 as compared to approximately 8.2 million tons sold and approximately 7.1 million tons produced for the year ended December 31, 2007, on a pro forma basis. We forecast that our cost of operations per ton for the twelve months ending June 30, 2009 will be $42.45 as compared to $39.04 for the year ended December 31, 2007, on a pro forma basis. Inflationary increases are also forecasted to be approximately

3.0% for labor, supplies and services used in mining. We forecast that royalties and production taxes will increase for the twelve months ending June 30, 2009 as a result of additional tons being produced and sold at higher average coal prices per ton. 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.

Depreciation, Depletion and Amortization. We forecast depreciation, depletion and amortization expense to be approximately $38.8 million for the twelve months ending June 30, 2009 as compared to approximately $30.8 million for the year ended December 31, 2007, on a pro forma basis. The increase in depreciation, depletion and amortization expense of approximately $8.0 million is primarily due to increased capital expenditures associated with our recent acquisitions, which will cause depreciation to increase by approximately $8.4 million for the twelve months ending June 30, 2009, an increase in depletion to approximately $1.4 million, which is due to an increase in coal production, and a decrease in amortization of approximately $1.8 million, which is due to lower amortization of assets being retired.

Selling, General and Administrative. We forecast selling, general and administrative expenses to be approximately $18.7 million for the twelve months ending June 30, 2009 as compared to approximately $15.4 million for the year ended December 31, 2007, 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.

Financing. We forecast interest expense of approximately $1.7 million for the twelve months ending June 30, 2009 as compared to approximately $1.8 million for the year ended December 31, 2007, on a pro forma basis. Our total debt balance as of December 31, 2007 was approximately $17.0 million on a pro forma basis. Our interest expense for the twelve months ending June 30, 2009 is based on the following assumptions:

•: Our outstanding indebtedness will be reduced by approximately $67.0 million after application of a portion of the proceeds from this offering.
•: For calculating our floating interest rate exposure, we have assumed an average interest rate of LIBOR plus 1.5% on our average debt level and a LIBOR of 5.39% based on forward curves as of January 2008 for an average interest rate of 6.89%.
•: We maintain a low cash balance to optimize our debt level.

Capital Expenditures. We forecast capital expenditures for the year ending June 30, 2009 based on the following assumptions:

•: Our estimated maintenance and replacement capital expenditures will be $33.0 million for the twelve months ending June 30, 2009 as compared to approximately $19.0 million of actual maintenance and replacement capital expenditures for the year ended December 31, 2007. We expect to fund maintenance and replacement capital expenditures from cash generated by our operations.
•: Our expansion capital expenditures will be approximately $14.2 million for the twelve months ending June 30, 2009 as compared to approximately $30.4 million of actual expansion capital expenditures for the year ended December 31, 2007. The actual expansion capital expenditures included our Sands Hill acquisition for approximately $18.2 million and other ancillary businesses for approximately $7.6 million. Other actual expansion capital expenditures accounted for approximately $4.6 million, which included the purchase of surface land in the Illinois Basin. The forecasted expansion capital expenditures consist of approximately $4.2 million for the

expansion of our Leesville field in Northern Appalachia and approximately $10.0 million for the purchase of surface land in the Illinois Basin. We will fund these expansion capital expenditures with borrowings under our credit facility or cash generated from operations.

Regulatory, Industry and Economic Factors. We forecast for the twelve months ending June 30, 2009 based on the following assumptions related to regulatory, industry and economic factors:

•: No material nonperformance or credit-related defaults by suppliers, customers or vendors, or shortage of skilled labor.
•: All supplies and commodities necessary for production and sufficient transportation will be readily available.
•: No new federal, state or local regulation of the portions of the mining industry in which we operate or any interpretation of existing regulation that in either case will be materially adverse to our business.
•: No material unforeseen geological conditions or equipment problems at our mining locations.
•: No material accidents, releases, weather-related incidents, unscheduled downtime or similar unanticipated events.
•: 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.

HOW WE MAKE CASH DISTRIBUTIONS

Distributions of Available Cash

General

Within 45 days after the end of each quarter, beginning with the fiscal quarter ending June 30, 2008, we will distribute 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 this offering through June 30, 2008 based on the actual length of the period.

Definition of Available Cash

Available cash generally means, for any quarter, all cash on hand at the end of the quarter:

•: less the amount of cash reserves established by our general partner to:
•: provide for the proper conduct of our business (including reserves for our future capital expenditures and credit needs) after that quarter;
•: comply with applicable law, any of our debt instruments or other agreements; and
•: provide funds for distributions to our unitholders and to our general partner for any one or more of the next four quarters;
•: plus all 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 for which the determination is being made. Working capital borrowings, which are made at the discretion of our general partner, are generally borrowings that are made under the credit agreement and in all cases are used solely for working capital purposes or to pay distributions to partners.

Intent to Distribute the Minimum Quarterly Distribution

We intend to make a minimum quarterly distribution to the holders of common units and subordinated units of $0.375 per unit, or $1.50 on an annualized basis, to the extent we have sufficient cash from our operations after the establishment of cash reserves and the payment of costs and expenses, including reimbursements of expenses to our general partner. However, there is no guarantee that we will pay the minimum quarterly distribution on our units in any quarter. Even if our cash distribution policy is not modified or revoked, the amount of distributions paid 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. Because our interest in Rhino Energy LLC will be our only cash generating asset upon the closing of this offering, the amount of our distributions to unitholders initially will depend completely upon distributions by Rhino Energy LLC to us. Rhino Energy LLC will be prohibited from making any distributions to us if it would cause an event of default, or an event of default exists, under its credit agreement. Please read "Management's Discussion and Analysis of Financial Condition and Results of Operations—Liquidity and Capital Resources—Credit Agreement" for a discussion of the restrictions to be included in the credit agreement that may restrict Rhino Energy LLC's ability to make distributions.

General Partner Interest and Incentive Distribution Rights

As of the date of this offering, our general partner will be entitled to 2% of all quarterly distributions that we make prior to our liquidation. Our general partner's initial 2% 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% general partner interest. Our general partner will also be issued the incentive distribution rights that entitle the holder to receive

increasing percentages, up to a maximum of 10%, of the cash we distribute from operating surplus (as defined below) in excess of $0.425 per unit. The maximum distribution of 10% includes distributions paid to our general partner on its 2% general partner interest. The maximum distribution of 10% does not include any distributions that our general partner may receive on common units or subordinated units that it owns. Please read "—Incentive Distribution Rights" for additional information.

Operating Surplus and Capital Surplus

Overview

All cash distributed to unitholders will be characterized as either "operating surplus" or "capital surplus." We treat distributions of available cash from operating surplus differently than distributions of available cash from capital surplus.

Definition of Operating Surplus

We define operating surplus in the glossary, and for any period it generally means:

•: $30.0 million (as described below); plus
•: all of our cash receipts after the closing of this offering, excluding cash from (1) borrowings that are not working capital borrowings, (2) sales of equity and debt securities and (3) sales or other dispositions of assets outside the ordinary course of business; plus
•: working capital borrowings made after the end of a quarter but before the date of determination of operating surplus for the quarter; plus
•: cash distributions paid on equity securities issued to finance all or a portion of the construction, replacement or improvement of a capital asset (such as equipment or reserves) during the period from such financing until the earlier to occur of the date the capital asset is put into service or the date that it is abandoned or disposed of; less
•: all of our operating expenditures (as defined below), including estimated maintenance and replacement capital expenditures, after the closing of this offering and the repayment of working capital borrowings, but not (1) the repayment of other borrowings, (2) actual maintenance and replacement capital expenditures, expansion capital expenditures or investment capital expenditures, (3) transaction expenses (including taxes) related to interim capital transactions or (4) cash distributions to our partners; less
•: the amount of cash reserves established by our general partner to provide funds for future operating expenditures.

If a working capital borrowing, which increases operating surplus, 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 is in fact repaid, it will not be treated as a further reduction in operating surplus because operating surplus will have been previously reduced by the deemed repayment.

As described above, operating surplus does not reflect actual cash on hand that is available for distribution to our unitholders. For example, it includes a provision that will enable us, if we choose, to distribute as operating surplus up to $30.0 million of 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 in operating surplus, as described above, certain cash distributions on equity securities issued to finance a capital asset until it is placed into service or abandoned would be to increase our 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 distribution or interest payments of cash we receive from non-operating sources.

We define operating expenditures in the glossary, and it generally means all of our expenditures, including, but not limited to, taxes, reimbursements of expenses to our general partner, repayment of working capital borrowings, debt service payments and estimated maintenance and replacement capital expenditures, provided that operating expenditures will not include:

•: payments (including prepayments) of principal of and premium on indebtedness, other than working capital borrowings;
•: expansion capital expenditures;
•: actual maintenance and replacement capital expenditures;
•: investment capital expenditures;
•: payment of transaction expenses relating to interim capital transactions; or
•: distributions to partners.

Maintenance and replacement capital expenditures are those capital expenditures required to maintain or replace our capital asset base. Examples of maintenance and replacement capital expenditures include 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 incurred to maintain or replace our capital asset base. Maintenance and replacement capital expenditures will also include interest (and related fees) on debt incurred and distributions on equity issued to finance all or any portion of the replacement, repaired or improved asset during the period from such financing until the earlier to occur of the date any such asset is put into service or the date that it is abandoned or permanently taken out of service. Mine closing and similar costs will also be considered maintenance and replacement capital expenditures.

Because our maintenance and replacement capital expenditures can be very large and irregular, the amount of our actual maintenance and replacement 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 and replacement capital expenditures from operating surplus. Accordingly, to eliminate the effect on operating surplus of these fluctuations, our partnership agreement will require that an estimate of the average quarterly maintenance and replacement capital expenditures necessary to maintain or replace our capital asset base be subtracted from operating surplus each quarter, as opposed to the actual amounts spent. The amount of estimated maintenance and replacement 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 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 and replacement capital expenditures, such as a major acquisition or the introduction of new governmental regulations that will impact our business. For purposes of calculating operating surplus, any adjustment to this estimate will be prospective only.

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

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

•: it will increase our ability to distribute as operating surplus cash we receive from non-operating sources;
•: it will be more difficult for us to raise our distribution above the minimum quarterly distribution and pay incentive distributions to our general partner; and
•: it will reduce the likelihood that a large maintenance capital expenditure in a period will prevent our general partner's affiliates from being able to convert some or all of their subordinated units into common units since the effect of an estimate is to spread the expected expense over several periods, thereby mitigating the effect of the actual payment of the expenditure on any single period.

Expansion capital expenditures are those capital expenditures made to increase or expand our capital asset base. 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 incurred to increase or expand our capital asset base. Expansion capital expenditures will also include interest (and related fees) on debt incurred and distributions on equity issued to finance all or any portion of such capital improvement during the period from such financing until the earlier to occur of the date any such capital improvement is put into service or the date that it is abandoned or disposed of.

As described above, neither actual maintenance and replacement capital expenditures nor expansion capital expenditures are subtracted from operating surplus. Because actual maintenance and replacement capital expenditures and expansion capital expenditures include interest payments (and related fees) on debt incurred and distributions on equity issued to finance the cost of all or any portion of the construction, replacement or improvement of a capital asset (such as equipment or reserves) during the period from such financing until the earlier to occur of the date any such capital asset is put into service or the date that it is abandoned or disposed of, such interest payments and equity distributions are also not subtracted from operating surplus (except to the extent such interest payments and distributions are included in estimated maintenance and replacement capital expenditures). Not subtracting such interest payments and equity distributions from operating surplus will increase the likelihood that we will meet the tests for termination of the subordination period (as described below).

Investment capital expenditures are those capital expenditures made solely for investment purposes and not intended to be either maintenance and replacement capital expenditures or expansion capital expenditures. Examples of investment capital expenditures include traditional investments, such as purchases of securities, as well as other investments, such as the acquisition of a capital asset that is not intended to maintain or replace or increase or expand our capital asset base.

Definition of Capital Surplus

We also define capital surplus in the glossary, and it will generally be generated only by:

•: borrowings other than working capital borrowings;
•: sales of debt and equity securities; and
•: sales or other disposition of assets for cash, other than inventory, accounts receivable and other current assets sold in the ordinary course of business or as part of normal retirements or replacements of assets.

Characterization of Cash Distributions

We will treat all available cash distributed as coming from operating surplus until the sum of all available cash distributed since we began operations equals the operating surplus as of the most recent

date of determination of available cash. We will treat any amount distributed in excess of operating surplus, regardless of its source, as capital surplus. As reflected above, operating surplus includes $30.0 million and cash from working capital borrowings, in addition to cash receipts from our operating activities. The $30.0 million amount does not reflect actual cash on hand at closing that is available for distribution to our unitholders. Rather, it is a provision that will enable us, if we choose, to distribute as operating surplus up to $30.0 million of 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. We do not anticipate that we will make any distributions from capital surplus.

Subordination Period

General

During the subordination period, which we define below and in the glossary, the common units will have the right to receive distributions of available cash from operating surplus in an amount equal to the minimum quarterly distribution of $0.375 per quarter, plus any arrearages 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. Wexford Funds will own all outstanding subordinated units, representing a 10.0% limited partner interest in us. Certain executive officers and directors of our general partner are Wexford Principals. 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 distributions until the common units have received the minimum quarterly distribution plus any arrearages from prior quarters. Furthermore, no arrearages will be paid on the subordinated units. The practical effect of the subordination period is to increase the likelihood that during this period there will be sufficient available cash to pay the minimum quarterly distribution on the common units.

Definition of Subordination Period

Except as described below under "—Early Termination of the Subordination Period," the subordination period will extend until the first day of any quarter beginning after June 30, 2013 that each of the following tests are met:

•: distributions of available cash from operating surplus on each of the outstanding common units 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 units and subordinated units during those periods on a fully diluted basis and on the general partner interest during those periods; and
•: there are no arrearages in payment of the minimum quarterly distribution on the common units.

In addition, if the unitholders remove our general partner other than for cause and no units held by our general partner and its affiliates are voted in favor of such removal:

•: the subordination period will end and each subordinated unit will immediately convert into one common unit;

•: any existing arrearages in payment of the minimum quarterly distribution on the common units will be extinguished; and
•: our general partner will have the right to convert its general partner interest and its incentive distribution rights into common units or to receive cash in exchange for those interests.

Early Conversion of Subordinated Units

If the tests for ending the subordination period are satisfied for any three consecutive four-quarter periods ending on or after June 30, 2011, 25% of the subordinated units will convert into an equal number of common units. Similarly, if those tests are also satisfied for any three consecutive four-quarter periods ending on or after June 30, 2012, an additional 25% of the subordinated units will convert into an equal number of common units. The second early conversion of subordinated units may not occur, however, until at least one year following the end of the period for the first early conversion of subordinated units.

For purposes of determining whether sufficient adjusted operating surplus has been generated under these conversion tests, the conflicts committee may adjust operating surplus upwards or downwards if it determines in good faith that the amount of estimated maintenance and replacement capital expenditures used in the determination of operating surplus was materially incorrect, based on the circumstances prevailing at the time of the original estimate.

Early Termination of the Subordination Period

In addition to the early conversion of subordinated units described above, the subordination period will automatically terminate and all of the subordinated units will convert into common units on a one-for-one basis if each of the following occurs:

•: distributions of available cash from operating surplus on each outstanding common unit and subordinated unit equaled or exceeded $2.00 (133% of the annualized minimum quarterly distribution) for a single four-quarter period immediately preceding that date;
•: the "adjusted operating surplus" (as defined below) generated during a single four-quarter period immediately preceding that date equaled or exceeded the sum of a distribution of $2.00 (133% of the annualized minimum quarterly distribution) on all of the outstanding common units and subordinated units on a fully diluted basis; and
•: there are no arrearages in payment of the minimum quarterly distribution on the common units.

Definition of Adjusted Operating Surplus

We define adjusted operating surplus in the glossary and for any period it generally means:

•: operating surplus generated with respect to that period (which excludes operating surplus attributable to the first bullet point under the caption "—Operating Surplus and Capital Surplus—Definition of Operating Surplus," above; less
•: any net increase in working capital borrowings with respect to that period; less
•: any net reduction 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 made with respect to that period required by any debt instrument for the repayment of principal, interest or premium.

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 is calculated using estimated maintenance and replacement capital expenditures, rather than actual maintenance and replacement capital expenditures and, to the extent the estimated amount for a period is less than the actual amount, the cash generated from operations during that period would be less than adjusted operating surplus.

Effect of Expiration of the Subordination Period

Upon expiration of the subordination period, 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.

Distributions of Available Cash from Operating Surplus during the Subordination Period

We will make distributions of available cash from operating surplus for any quarter during the subordination period in the following manner:

•: first, 98% to the common unitholders, pro rata, and 2% to our general partner, until we distribute for each outstanding common unit an amount equal to the minimum quarterly distribution for that quarter;
•: second, 98% to the common unitholders, pro rata, and 2% to our general partner, until we distribute for each outstanding 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% to the subordinated unitholders, pro rata, and 2% 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 "—Incentive Distribution Rights" below.

The preceding discussion is based on the assumption that we do not issue additional classes of equity securities and that our general partner maintains its 2% general partner interest.

Distributions of Available Cash from Operating Surplus after the Subordination Period

We will make distributions of available cash from operating surplus for any quarter after the subordination period in the following manner:

•: first, 98% to all unitholders, pro rata, and 2% to our general partner, until we distribute for each outstanding unit an amount equal to the minimum quarterly distribution for that quarter; and
•: thereafter, in the manner described in "—Incentive Distribution Rights" below.

The preceding discussion is based on the assumption that we do not issue additional classes of equity securities and that our general partner maintains its 2% general partner interest.

Incentive Distribution Rights

Incentive distribution rights represent the right to receive an increasing percentage 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 will initially hold the incentive distribution rights, but may transfer these rights separately from its general partner interest, subject to restrictions in our partnership agreement.

If for any quarter:

•: we have distributed available cash from operating surplus to the unitholders in an amount equal to the minimum quarterly distribution; and
•: we have distributed available cash from operating surplus on outstanding common units and the general partner interest in an amount necessary to eliminate any cumulative arrearages in payment of the minimum quarterly distribution to the common unitholders;

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

•: first, 98% to all unitholders, pro rata, and 2% to our general partner, until each unitholder receives a total of $0.425 per unit for that quarter (the "first target distribution");
•: second, 96% to all unitholders, pro rata, and 4% to our general partner, until each unitholder receives a total of $0.450 per unit for that quarter (the "second target distribution");
•: third, 94% to all unitholders, pro rata, and 6% to our general partner, until each unitholder receives a total of $0.475 per unit for that quarter (the "third target distribution");
•: fourth, 92% to all unitholders, pro rata, and 8% to our general partner, until each unitholder receives a total of $0.500 per unit for that quarter (the "fourth target distribution"); and
•: thereafter, 90% to all unitholders, pro rata, and 10% to our general partner.

In each case, the amount of the target distribution set forth above is exclusive of any distributions to common unitholders to eliminate any cumulative arrearages in payment of the minimum quarterly distribution to the common unitholders. The preceding discussion is based on the assumptions that our general partner has not transferred its incentive distribution rights, that we do not issue additional classes of equity securities and that our general partner maintains its 2% general partner interest.

Percentage Allocations of Available Cash from Operating Surplus

The following table illustrates the percentage allocations of the additional available cash from operating surplus between the unitholders and our general partner up to the various 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 Target Amount," until available cash from operating surplus we distribute reaches the next target distribution level, if any. The percentage interests shown for the 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 assume that our general partner has not transferred its incentive distribution rights.

		Marginal Percentage Interest in Distributions
	Total Quarterly Distribution Target Amount	Unitholders		General Partner
Minimum Quarterly Distribution	$0.375	98	%	2	%
First Target Distribution	up to $0.425	98	%	2	%
Second Target Distribution	above $0.425 up to $0.450	96	%	4	%
Third Target Distribution	above $0.450 up to $0.475	94	%	6	%
Fourth Target Distribution	above $0.475 up to $0.500	92	%	8	%
Thereafter	above $0.500	90	%	10	%

Distributions from Capital Surplus

How Distributions from Capital Surplus Will Be Made

We will make distributions of available cash from capital surplus, if any, in the following manner:

•: first, to all unitholders, pro rata, 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, to the common unitholders, pro rata, 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 discussion is based on the assumption that we do not issue additional classes of equity securities and that our general partner maintains its 2% general partner interest.

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, after any of these distributions are made, it may be easier for our general partner to receive the increased 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, we will reduce the minimum quarterly distribution and the target distribution levels to zero. We will then make all future distributions from operating surplus, with 90% being paid to the unitholders, pro rata, and 10% to our general partner. The percentage interests shown assume that our general partner has not transferred the incentive distribution rights, that we do not issue additional classes of equity securities and that our general partner maintains its 2% general partner interest.

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, we will proportionately adjust:

•: the minimum quarterly distribution;
•: target distribution levels; and
•: the unrecovered initial unit price.

For example, if a two-for-one split of the common and subordinated units should occur, the minimum quarterly distribution, the target distribution levels and the unrecovered initial unit price would each be reduced to 50% of its initial level. If we combine our common units into fewer units or subdivide our common units into a greater number of units, we will combine our subordinated units or subdivide our subordinated units, using the same ratio applied to the common units. We will 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 court of competent jurisdiction, so that we become taxable as a corporation or otherwise subject to taxation as an entity for federal, state or local income tax purposes, we will reduce the minimum quarterly distribution and the target distribution levels for each quarter by multiplying each distribution level by a fraction, the numerator of which is available cash for that quarter (after deducting our general partner's estimate of our aggregate liability for the quarter for such income taxes payable by reason of such legislation or interpretation) 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.

The amount of distributions paid 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.

Distributions of Cash Upon Liquidation

General

If we dissolve in accordance with our 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 and our general partner, 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 outstanding common units to a preference over the holders of outstanding 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 liquidation to enable the holders of common units to fully recover all of these amounts, even though 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, currently owned by our general partner.

Manner of Adjustments for Gain

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

•

first, to our general partner and the holders of units who have negative balances in their capital accounts to the extent of and in proportion to those negative balances;

•

second, 98% to the common unitholders, pro rata, and 2% 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% to the subordinated unitholders, pro rata, and 2% 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% to all unitholders, pro rata, and 2% 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% to the unitholders, pro rata, and 2% to our general partner, for each quarter of our existence;

•

fifth, 96% to all unitholders, pro rata, and 4% 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 96% to the unitholders, pro rata, and 4% to our general partner for each quarter of our existence;

•

sixth, 94% to all unitholders, pro rata, and 6% 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 94% to the unitholders, pro rata, and 6% to our general partner for each quarter of our existence;

•

seventh, 92% to all unitholders, pro rata, and 8% to our general partner, until we allocate under this paragraph an amount per unit equal to:

(1): the sum of the excess of the fourth target distribution per unit over the third 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 third target distribution per unit that we distributed 92% to the unitholders, pro rata, and 6% to our general partner for each quarter of our existence; and

•

thereafter, 90% to all unitholders, pro rata, and 10% to our general partner.

The percentages set forth above are based on the assumption that our general partner has not transferred its incentive distribution rights, that we do not issue additional classes of equity securities and that our general partner maintains its 2% general partner interest.

If the liquidation occurs after the end of the subordination period, the distinction between common units 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, we will generally allocate any loss to our general partner and unitholders in the following manner:

•: first, 98% to holders of subordinated units in proportion to the positive balances in their capital accounts and 2% to our general partner, until the capital accounts of the subordinated unitholders have been reduced to zero;
•: second, 98% to the holders of common units in proportion to the positive balances in their capital accounts and 2% to our general partner, until the capital accounts of the common unitholders have been reduced to zero; and
•: thereafter, 100% to our general partner.

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

Adjustments to Capital Accounts

We will make adjustments to capital accounts upon the issuance of additional units. In doing so, we will allocate any unrealized and, for tax purposes, unrecognized gain or loss resulting from the adjustments to the unitholders and our general partner in the same manner as we allocate gain or loss upon liquidation. In the event that we make positive adjustments to the capital accounts upon the issuance of additional units, we will 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 our general partner's capital account balances equaling the amount which they would have been if no earlier positive adjustments to the capital accounts had been made.

SELECTED HISTORICAL AND PRO FORMA CONSOLIDATED
FINANCIAL AND OPERATING DATA

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

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

•: the distribution by Rhino Energy LLC of its ownership interests in CAM-Colorado LLC, an entity that owns certain properties located in Colorado that will not be retained by us, to NR Energy LLC, an entity owned by certain Wexford Funds;
•: the contribution by Rhino Energy Holdings LLC, which is also owned by certain Wexford Funds, of 100% of the ownership interests in Rhino Energy LLC to us;
•: the issuance by us to Rhino Energy Holdings LLC of an aggregate of 27,925,200 common units and 3,741,500 subordinated units, representing a combined 84.6% limited partner interest in us;
•: the issuance by us to our general partner of the incentive distribution rights, which entitle the holder to increasing percentages, up to a maximum of 10%, of the cash we distribute in excess of $0.425 per unit per quarter. Our general partner will also maintain its 2% general partner interest in us; and
•: the issuance by us to the public of 5,000,000 common units, representing a 13.4% limited partner interest in us, and the use of the net proceeds from this offering as described under "Use of Proceeds."

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

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

The following table presents a non-GAAP financial measure, EBITDA, which we use in our business as it is an important supplemental measure of our performance and liquidity. EBITDA means

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

			Rhino Energy LLC Historical Consolidated																		Rhino Resource Partners, L.P. Pro Forma Consolidated
			Period from April 30, 2003 (date of inception) through December 31, 2003
						Three Months Ended March 31, 2004			Year Ended March 31,						Nine Months Ended December 31, 2006
									Year Ended March 31,									Year Ended December 31, 2007			Year Ended December 31, 2007
									2005			2006						Year Ended December 31, 2007			Year Ended December 31, 2007
			(in thousands, except per unit and per ton data)
Statement of Operations Data:
Total revenues			$	33,901.4		$	16,224.7		$	279,977.8		$	363,959.9		$	300,838.5		$	403,451.8		$	403,443.2
Costs and expenses:
	Cost of operations (exclusive of depreciation, depletion and amortization shown separately below)			25,841.3			14,056.4			220,628.7			291,444.7			238,189.7			318,520.6			318,531.7
	Freight and handling costs			578.4			570.1			7,245.3			6,342.5			2,768.1			4,020.7			4,020.7
	Depreciation, depletion and amortization			1,715.8			698.3			4,583.4			13,744.3			28,471.2			30,749.8			30,749.8
	Selling, general and administrative			4,735.7			1,191.0			12,877.5			17,129.4			18,573.0			15,370.3			15,369.7
	(Gain) loss on sale of assets			(109.9	)		48.3			505.7			(377.2	)		745.8			(944.3	)		(944.3	)
	(Gain) loss on retirement of advance royalties			—			—			—			(236.9	)		2,994.6			(115.3	)		(115.3	)

		Total costs and expenses		32,761.3			16,564.1			245,840.6			328,046.8			291,742.4			367,601.8			367,612.3

Income (loss) from operations				1,140.1			(339.4	)		34,137.2			35,913.1			9,096.1			35,850.0			35,830.9
Interest and other income (expense):
	Interest expense			(565.0	)		(287.9	)		(3,454.7	)		(4,976.2	)		(6,498.0	)		(5,579.2	)		(1,800.8	)
	Interest income			30.2			13.1			442.3			412.1			311.7			316.7			316.7
	Other—net			109.8			(6.7	)		(1,296.4	)		490.7			272.2			—			—

Total interest and other income (expense)				(425.0	)		(281.5	)		(4,308.8	)		(4,073.4	)		(5,914.1	)		(5,262.5	)		(1,484.1	)

Income (loss) before income tax expense and cumulative effect of change in accounting principle				715.1			(620.9	)		29,828.4			31,839.7			3,182.0			30,587.5			34,346.8
Income tax expense (benefit)				—			—			73.8			178.4			124.6			(126.3	)		(126.3	)

Net income (loss) before cumulative effect of change in accounting principles				715.1			(620.9	)		29,754.6			31,661.3			3,057.4			30,713.8			34,473.1
Cumulative effect of change in accounting principle—net of taxes				—			—			1,656.4			—			—			—			—

Net income (loss) before			$	715.1		$	(620.9	)	$	28,098.2		$	31,661.3		$	3,057.4		$	30,713.8		$	34,473.1
Other comprehensive income (loss):
	Change in actuarial gain/(loss) under SFAS No. 158			—			—			—			—			(901.0	)		1,489.4			1,489.4

Net comprehensive income (loss)			$	715.1		$	(620.9	)	$	28,098.2		$	31,661.3		$	2,156.4		$	32,203.2		$	35,962.5

			Rhino Energy LLC Historical Consolidated																		Rhino Resource Partners, L.P. Pro Forma Consolidated
			Period from April 30, 2003 (date of inception) through December 31, 2003
						Three Months Ended March 31, 2004			Year Ended March 31,						Nine Months Ended December 31, 2006
									Year Ended March 31,									Year Ended December 31, 2007			Year Ended December 31, 2007
									2005			2006						Year Ended December 31, 2007			Year Ended December 31, 2007
			(in thousands, except per unit and per ton data)
Net income per limited partner unit, basic and diluted:
	Common units																				$	1.03
	Subordinated units																				$	—
Weighted average number of limited partner units outstanding, basic and diluted:
	Common units																					32,925.2
	Subordinated units																					3,741.5
Statement of Cash Flows Data:
Net cash provided by (used in):
	Operating activities		$	(568.2	)	$	(1,079.1	)	$	33,142.6		$	32,892.0		$	36,859.5		$	52,492.5		$	55,756.7
	Investing activities		$	(20,796.1	)	$	(13,406.2	)	$	(47,182.2	)	$	(34,612.6	)	$	(28,827.6	)	$	(28,097.6	)
	Financing activities		$	21,368.0		$	14,485.1		$	19,132.5		$	(1,886.9	)	$	(9,140.8	)	$	(21,191.5	)
Other Financial Data:
EBITDA(1)			$	2,995.9		$	365.3		$	36,210.0		$	50,560.2		$	38,151.2		$	66,916.5		$	66,897.4
Maintenance and replacement capital expenditures			$	6,443.1		$	1,928.8		$	22,547.1		$	32,348.2		$	20,952.4		$	19,047.2		$	19,047.2
Expansion capital expenditures				10,605.0			12,600.0			25,429.0			31,525.1			18,357.0			31,162.5			30,360.8

		Total capital expenditures	$	17,048.1		$	14,528.8		$	47,976.1		$	63,873.3		$	39,309.4		$	50,209.7		$	49,408.0

Balance Sheet Data (at period end):
Cash and cash equivalents			$	3.6		$	3.4		$	5,096.3		$	1,488.8		$	380.0		$	3,583.4		$	3,583.4
Property and equipment, net			$	26,805.5		$	42,818.8		$	128,407.4		$	180,267.0		$	197,056.1		$	211,657.1		$	193,869.3
Total assets			$	41,163.6		$	59,422.1		$	181,138.4		$	246,759.3		$	248,194.5		$	275,992.2		$	258,200.3
Total liabilities			$	24,568.2		$	43,644.6		$	120,068.7		$	154,028.4		$	153,307.1		$	158,151.7		$	91,352.4
Total debt			$	16,597.1		$	31,279.2		$	61,941.9		$	87,764.1		$	88,570.5		$	83,953.7		$	16,953.7
Members'/partners' equity			$	16,595.4		$	15,777.5		$	61,069.6		$	92,730.9		$	94,887.4		$	117,840.5		$	166,847.8
Operating Data:
Tons of coal sold				1,058.6			455.4			7,051.6			7,900.3			6,222.9			8,159.0
Tons of coal produced				1,122.1			511.5			7,201.6			7,950.1			6,182.0			7,056.6
Coal revenues per ton(2)			$	31.25		$	35.42		$	38.63		$	44.48		$	47.31		$	48.30
Cost of operations per ton(3)			$	24.96		$	32.12		$	32.32		$	36.89		$	38.28		$	39.04

(1)

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

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

		Rhino Energy LLC Historical Consolidated															Rhino Resource Partners, L.P. Pro Forma Consolidated
		Period from April 30, 2003 (date of inception) through December 31, 2003
					Three Months Ended March 31, 2004			Year Ended March 31,				Nine Months Ended December 31, 2006
								Year Ended March 31,						Year Ended December 31, 2007			Year Ended December 31, 2007
								2005		2006				Year Ended December 31, 2007			Year Ended December 31, 2007
		(in thousands)
Reconciliation of EBITDA to net income:
Net income (loss)		$	715.1		$	(620.9	)	$	29,098.2	$	31,661.3	$	3,057.4	$	30,713.8		$	34,473.1
Plus:
	Depreciation, depletion and amortization		1,715.8			698.3			4,583.4		13,744.3		28,471.2		30,749.8			30,749.8
	Interest expense		565.0			287.9			3,454.7		4,976.2		6,498.0		5,579.2			1,800.8
	Income tax expense (benefit)		—			—			73.8		178.4		124.6		(126.3	)		(126.3	)

EBITDA		$	2,995.9		$	365.3		$	36,210.1	$	50,560.2	$	38,151.2	$	66,916.5		$	66,897.4

Reconciliation of EBITDA to net cash provided by (used in) operating activities:
Net cash provided by (used in) operating activities		$	(568.2	)	$	(1,079.1	)	$	33,142.6	$	32,892.0	$	36,859.5	$	52,492.5		$	55,756.7
Plus:
	Increase in net operating assets		2,889.2			1,676.9			3,176.6		16,447.4		892.7		10,552.7			11,047.8
	Decrease in provision for doubtful accounts		—			—			—		—		282.8		175.2			175.2
	Gain on sale of assets		—			—			—		377.2		—		944.3			944.3
	Gain on retirement of advance royalties		109.9			—			—		236.9		—		115.3			115.3
	Interest expense		565.0			287.9			3,454.7		4,976.2		6,498.0		5,579.2			1,800.8
	Income tax expense		—			—			73.8		178.4		124.6		—			—
Less:
	Accretion on interest-free debt		—			—			473.2		321.2		255.1		359.8			359.8
	Amortization of advance royalties		—			406.0			1,231.5		2,186.8		1,098.5		699.7			699.7
	Increase in provision for doubtful accounts		—			—			103.6		354.4		—		—			—
	Loss on sale of assets		—			48.3			505.7		—		745.8		—			—
	Loss on retirement of advance royalties		—			—			—		—		2,994.6		—			—
	Income tax benefit		—			—			—		—		—		126.3			126.3
	Accretion on asset retirement obligations		—			66.1			1,323.6		1,685.5		1,412.4		1,756.9			1,756.9

EBITDA		$	2,995.9		$	365.3		$	36,210.1	$	50,560.2	$	38,151.2	$	66,916.5		$	66,897.4

(2): Coal revenues per ton represent total coal revenues derived from the sale of coal from all business segments, divided by total tons of coal sold for all segments.
(3): Cost of operations per ton represents the cost of operations (exclusive of depreciation, depletion and amortization) from all business segments divided by total tons of coal sold for all segments.

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

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

Overview

As of October 31, 2007, we controlled approximately 222.3 million tons of proven and probable coal reserves and approximately 97.8 million tons of non-reserve coal deposits. We completed the acquisitions of the Sands Hill mining complex located in Northern Appalachia in December 2007 and the Deane mining complex located in Central Appalachia in February 2008 and entered into a lease with respect to the Bolt field located in Central Appalachia in February 2008, which together added a total of approximately 33.9 million tons of proven and probable coal reserves and approximately 28.7 million tons of non-reserve coal deposits. We expect to produce approximately 1.8 million tons of coal in 2009 from our recently acquired mining complexes. We produce high quality coal that is sold in both the steam and metallurgical coal markets. We market our steam coal primarily to electric utilities, the majority of which are rated investment grade. The metallurgical coal that we produce is sold for end use by domestic and international steel producers. In addition, the Sands Hill mining complex added approximately 21.6 million tons of proven and probable limestone reserves and approximately 3.7 million tons of non-reserve limestone deposits.

Our results of operations in the near term could be impacted by a number of factors, including (1) adverse weather conditions and natural disasters, (2) poor mining conditions resulting from geological conditions or the effects of prior mining, (3) equipment problems at mining locations, (4) the availability of transportation for coal shipments or (5) the availability and costs of key supplies and commodities such as steel, tires, diesel fuel and explosives. On a long-term basis, our results of operations could be impacted by, among other factors, (1) changes in governmental regulation of the mining industry or the electric utility industry, (2) the availability and prices of competing electricity-

generation fuels, (3) our ability to secure or acquire high-quality coal reserves (4) our ability to find buyers for coal under supply contracts with terms comparable to those under existing contracts.

We conduct business through two principal reportable segments: Central Appalachia and Northern Appalachia. Our Central Appalachia segment consists of three mining complexes: Tug River, Rob Fork and Deane (which we acquired in February 2008), which together include ten underground mines, six surface mines and five preparation and/or loadout facilities in eastern Kentucky and southern West Virginia. Our Northern Appalachia segment consists of the Hopedale mining complex. For the year ended December 31, 2007, our Other segment includes the results of our Colorado operations, the Sands Hill mining complex located in southern Ohio (which we acquired in December 2007), reserves in the Illinois Basin and our ancillary businesses.

One of our business strategies is to expand our operations through strategic acquisitions, including the acquisition of stable, cash generating, coal and non-coal natural resource assets. We believe that such assets would allow us to grow our cash available for distribution to our unitholders and enhance the stability of our cash flows. With respect to non-coal natural resource assets, we may acquire assets that may serve as a natural hedge to help mitigate our exposure to certain operating costs, such as diesel fuel. Our sponsor, Wexford, has substantial experience in acquiring and operating natural resource assets and will continue to assist us in identifying growth opportunities and additional management with the relevant expertise in acquiring such assets.

Recent Trends and Economic Factors Affecting the Coal Industry

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

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

•: Promulgation of more stringent mine safety laws. Mining accidents in the last several years in West Virginia, Kentucky and Utah have received national attention and instigated responses at the state and national levels that have resulted in increased scrutiny of current safety practices and procedures at all mining operations, particularly underground mining operations. More stringent mine safety laws and regulations promulgated by these states and the federal government have included increased sanctions for non-compliance. Implementing and complying with these new laws and regulations imposes additional costs on coal producers. Other states have proposed or passed similar bills, resolutions or regulations addressing mine safety practices.
•: Shortage of skilled labor and rising labor costs. The coal industry is experiencing a shortage of skilled labor and rising labor costs, due in large part to increased demand by coal producers attempting to increase production in response to the strong market demand for coal and to demographic changes as existing miners are retiring at a faster rate than the rate at which new miners are entering the mining workforce. In the event the shortage of experienced labor continues or worsens or coal producers are unable to train the necessary amount of skilled laborers, there could be an adverse impact on labor productivity and costs and our ability to expand production. Further, as a result of current market conditions and the high demand for

skilled labor in the regions in which we operate, we are experiencing a record level of labor costs.

•: Delays in obtaining and renewing permits. Numerous governmental permits or approvals are required for mining operations. The permitting process can extend over several years. The permitting rules are complex and the public frequently has the right to comment on permit applications and otherwise participate in the permitting process, including through court intervention, which can delay the issuance of or renewal of permits. Such delays in obtaining and renewing permits have an obvious detrimental effect on the ability of coal producers to conduct their mining operations.
•: Rising prices of basic mining materials. Coal mining operations use significant amounts of steel, petroleum products and other raw materials in various pieces of mining equipment, supplies and materials. The coal industry has seen the price of steel, petroleum products and other materials increase, a trend that has continued through the first quarter of 2008. Prices for basic mining materials such as diesel fuel and explosives have also increased.

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

Results of Operations

Evaluating Our Results of Operations

Our management uses a variety of financial measurements to analyze our performance. These measurements include (1) EBITDA, (2) coal revenues per ton 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 from operations before deducting interest expense, depreciation, depletion and amortization, and income taxes. EBITDA is used by management primarily as a measure of our segments' operating performance. Because not all companies calculate EBITDA identically, our calculation may not be comparable to similarly titled measures of other companies. Please read "—Reconciliation of EBITDA to Net Income by Segment" for reconciliations of EBITDA to net income on a segment basis for each of the periods indicated.

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

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

Comparability of Results of Operations

Effective April 1, 2006, Rhino Energy LLC changed its fiscal year end from March 31 to December 31. We present comparisons of our results of operations for the following periods:

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

Information for the year ended December 31, 2006 is derived from the unaudited historical consolidated financial statements of Rhino Energy LLC that are not included in this prospectus. Information for the year ended March 31, 2006, the nine months ended December 31, 2006 and the year ended December 31, 2007 is derived from the historical consolidated financial statements of Rhino Energy LLC that are included elsewhere in this prospectus. We include the comparison of our audited results of operations for the year ended December 31, 2007 to our unaudited results of operations for

the year ended December 31, 2006 as a supplement to the generally required comparisons of audited results of operations based on our belief that such a year-to-year comparison will enhance the reader's understanding of our results of operations.

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

The following table presents a non-GAAP financial measure, EBITDA, which we use in our business as it is an important supplemental measure of our performance and liquidity. EBITDA means earnings before interest, taxes, depreciation, depletion and amortization. This measure is not calculated or presented in accordance with GAAP. We explain this measure below and reconcile it to net income. Please read "—Reconciliation of EBITDA to Net Income by Segment" for reconciliations of EBITDA to net income on a segment basis for each of the periods indicated.

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

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

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

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

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

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

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

Other Financial Data:
EBITDA(1)			$	15,534.0		$	38,151.2		$	53,685.2		$	66,916.5

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

(1)

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

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

The following table presents a reconciliation of EBITDA to net income for each of the periods indicated.

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

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

(2): Coal revenues per ton represent total coal revenues, derived from the sale of coal from all business segments, divided by total tons of coal sold for all segments.
(3): Cost of operations per ton represents the cost of operations (exclusive of depreciation, depletion and amortization) from all business segments divided by total tons of coal sold for all segments.

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

For the year ended December 31, 2007, we sold 8.2 million tons of coal, which is 0.2 million fewer tons, or 2.3% less, than the 8.4 million tons of coal sold for the year ended December 31, 2006. Accordingly, our total revenues also declined slightly to $403.5 million for the year ended December 31, 2007 from $404.8 million for the year ended December 31, 2006. The decrease was minimal partly

because we were able to efficiently operate two mines in our Northern Appalachia segment for all of 2006 whereas, having completed the natural exhaustion of one mine and transitioned our operations, we operated two mines for only four months in 2007. Despite lower coal production and sales, both net income and EBITDA increased for the year ended December 31, 2007 from the year ended December 31, 2006. Net income increased to $30.7 million from $12.0 million for the year ended December 31, 2006, and EBITDA increased to $66.9 million for the year ended December 31, 2007 from $53.7 million for the year ended December 31, 2006. These increases in net income and EBITDA were due to higher coal revenues per ton for both steam and metallurgical coal and to our successful efforts to control the cost of operations.

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

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

	Total	8.4	8.2	(0.2	)	(2.3	%)

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

Tons of coal sold for the year ended December 31, 2007 decreased by 0.2 million tons, primarily due to lower production in our Northern Appalachia segment. We operated two mines in our Northern Appalachia segment for all of 2006 as compared to only four months in 2007 due to the natural exhaustion of one mine. Tons of coal sold in our Central Appalachia segment increased by 0.1 million, or 1.6%, to 6.6 million tons for the year ended December 31, 2007 from 6.5 million tons for the year ended December 31, 2006. For our Other segment, tons of coal sold was flat at 0.3 million tons for the year ended December 31, 2007.

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

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

	Total revenues	$	336.2	$	339.6	$	3.4		1.0	%

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

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

	Coal revenues per ton	$	33.53	$	37.34	$	3.81		11.4	%
Other
	Coal revenues	$	7.6	$	8.0	$	0.4		5.6	%
	Freight and handling revenues		1.6		1.7		0.1		6.4	%
	Other revenues		0.1		0.8		0.7		842.1	%

	Total revenues	$	9.3	$	10.5	$	1.2		13.2	%

	Coal revenues per ton	$	28.96	$	30.26	$	1.30		4.5	%
Total
	Coal revenues	$	394.5	$	394.1	$	(0.4	)	(0.1	)%
	Freight and handling revenues		4.4		4.1		(0.3	)	(7.9	)%
	Other revenues		5.9		5.3		(0.6	)	(9.7	)%

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

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

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

Our total revenues for the year ended December 31, 2007 decreased by $1.3 million, or 0.3%, to $403.5 million from $404.8 million for the year ended December 31, 2006. The slight decline in total revenues was due to decreased coal production in our Northern Appalachia segment. Coal revenues per ton were $48.30, an increase of $1.08, or 2.3%, from $47.22 per ton for the year ended December 31, 2006 primarily due to favorable quality adjustments for coal sold that was above the specification under the supply contracts. For our Central Appalachia segment, coal revenues increased by $4.4 million, or 1.3%, to $337.4 million for the year ended December 31, 2007 from $333.0 million for the year ended December 31, 2006. This increase in coal revenues was due to the sale of 1.0 million tons of coal purchased at favorable market prices during the year ended December 31, 2007. Coal revenues per ton for our Central Appalachia segment were $51.19 for the year ended December 31, 2007 as compared to $51.35 for the year ended December 31, 2006. For our Northern Appalachia segment, coal revenues were $48.7 million for the year ended December 31, 2007, a decrease of $5.2 million, or 9.6%, from the year ended December 31, 2006 due to the natural exhaustion of one mine, partially offset by higher coal revenues per ton. Coal revenues per ton for our Northern Appalachia segment increased 11.4%, to $37.34 per ton for the year ended December 31, 2007 from

$33.53 per ton for the year ended December 31, 2006, due to favorable quality adjustments for coal sold that was above the specification under the supply contracts. For our Other segment, coal revenues increased by $0.4 million, or 5.6%, to $8.0 million from $7.6 million for the year ended December 31, 2006. Coal revenues per ton for our Other segment were $30.26 for the year ended December 31, 2007, an increase of $1.30, or 4.5%, from $28.96 for the year ended December 31, 2006 as a result of a contractual price increase effective June 2007.

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

						Increase/(Decrease)
		Year Ended December 31, 2006		Year Ended December 31, 2007		Increase/(Decrease)
Segment		Year Ended December 31, 2006		Year Ended December 31, 2007		Dollars			%*
		(in millions, except per ton data and %)
Central Appalachia
	Cost of operations (exclusive of depreciation, depletion and amortization shown separately below)	$	272.8	$	272.8		—		—
	Freight and handling costs		0.6		1.2		0.6		97.0	%
	Depreciation, depletion and amortization		29.0		24.5		(4.5	)	(15.5	)%
	Selling, general and administrative		16.0		11.2		(4.8	)	(30.3	)%
	Cost of operations per ton	$	42.06	$	41.40	$	(0.66	)	(1.6	)%
Northern Appalachia
	Cost of operations (exclusive of depreciation, depletion and amortization shown separately below)	$	39.2	$	34.0	$	(5.2	)	(13.2	)%
	Freight and handling costs		2.3		1.2		(1.1	)	(46.2	)%
	Depreciation, depletion and amortization		3.8		4.2		0.4		9.2	%
	Selling, general and administrative		4.2		3.0		(1.2	)	(29.4	)%
	Cost of operations per ton	$	24.39	$	26.08	$	1.70		7.0	%
Other
	Cost of operations (exclusive of depreciation, depletion and amortization shown separately below)	$	11.1	$	11.6	$	0.5		4.5	%
	Freight and handling costs		1.6		1.7		0.1		2.2	%
	Depreciation, depletion and amortization		0.9		2.1		1.2		122.8	%
	Selling, general and administrative		1.0		1.2		0.2		19.8	%
	Cost of operations per ton	$	42.57	$	44.04	$	1.47		3.4	%
Total
	Cost of operations (exclusive of depreciation, depletion and amortization shown separately below)	$	323.1	$	318.5	$	(4.6	)	(1.4	)%
	Freight and handling costs		4.5		4.0		(0.5	)	(9.4	)%
	Depreciation, depletion and amortization		33.7		30.8		(2.9	)	(8.9	)%
	Selling, general and administrative		21.3		15.4		(5.9	)	(27.7	)%
	Cost of operations per ton	$	38.68	$	39.04	$	0.36		0.9	%

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

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

Our cost of operations for our Central Appalachia segment remained flat as we produced 1.3 million fewer tons but purchased coal cost increased by $35.9 million as we bought 1.0 million tons of coal for the year ended December 31, 2007 as compared to the same period in 2006. Our cost of operations per ton decreased to $41.40 for the year ended December 31, 2007 from $42.06 for the year ended December 31, 2006. This decrease was primarily due to lower outside services and trucking costs, which decreased $0.44 and $0.73 per ton, respectively, for the year ended December 31, 2007. These decreases were offset in part by increased labor and operating supplies costs of $0.30 and $0.34 per ton, respectively, for the year ended December 31, 2007.

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

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

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

Depreciation, Depletion and Amortization. Total depreciation, depletion and amortization ("DD&A") expense for the year ended December 31, 2007 was $30.8 million as compared to $33.7 million for the year ended December 31, 2006. The decrease in DD&A expense was primarily due to a decrease in depletion.

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

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

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

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

								Increase/(Decrease)
		Year Ended December 31, 2006			Year Ended December 31, 2007			Increase/(Decrease)
Segment		Year Ended December 31, 2006			Year Ended December 31, 2007			Dollars		%*
		(in millions, except %)
Central Appalachia		$	7.9		$	23.1		$	15.2	192.0	%
Northern Appalachia			6.7			9.1			2.4	36.1	%
Other			(2.5	)		(1.4	)		1.1	42.8	%

	Total	$	12.0		$	30.7		$	18.7	155.1	%

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

For the year ended December 31, 2007, total net income increased to $30.7 million from $12.0 million for the year ended December 31, 2006. This increase was due to higher coal revenues per ton, lower SG&A expense, lower DD&A expense, lower interest expense, gains from asset sales and retirement of advanced royalties and the reversal of income tax expense. In addition, in October 2006, our lease for the Bolt field in West Virginia was cancelled, resulting in a write-off of $2.1 million. In February 2008, we re-entered into a lease with respect to our Bolt field. For our Central Appalachia segment, net income increased to $23.1 million for the year ended December 31, 2007, an increase of 192.0% primarily due to higher coal sales, lower SG&A expense, lower DD&A expense and lower interest and income tax expenses, as well as gains on sales of assets and on the retirement of advanced royalties. Net income in our Northern Appalachia segment also increased by $2.4 million, or 36.1%, to $9.1 million for the year ended December 31, 2007, primarily due to higher coal revenues per ton. For our Other segment, net loss decreased by $1.1 million, primarily due to increased revenues and reduced cost from our ancillary businesses for the year ended December 31, 2007.

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

							Increase/(Decrease)
		Year Ended December 31, 2006			Year Ended December 31, 2007		Increase/(Decrease)
Segment		Year Ended December 31, 2006			Year Ended December 31, 2007		Dollars		%*
		(in millions, except %)
Central Appalachia		$	42.7		$	51.6	$	8.9	20.8	%
Northern Appalachia			11.6			14.0		2.4	20.2	%
Other			(0.6	)		1.3		2.0	n/m

	Total	$	53.7		$	66.9	$	13.3	24.6	%

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

Total EBITDA for the year ended December 31, 2007 was $66.9 million, an increase of $13.3 million, or 24.6%, from the year ended December 31, 2006. This increase in EBITDA was due to higher coal revenues and lower cost of operations, despite rising market prices for basic commodities used in mining such as diesel fuel, explosives and steel products for roof support used in our underground mining. EBITDA for our Central Appalachia segment increased by $8.9 million for the year ended December 31, 2007, due to higher coal revenues per ton and lower cost of operations per ton. EBITDA for our Northern Appalachia segment increased by $2.4 million for the year ended December 31, 2007, due to an increase in operating margins as a result of higher coal revenues per ton. For our Other segment, EBITDA for the year ended December 31, 2007 was $1.3 million as

compared to a negative $0.6 million for the year ended December 31, 2006. Please read "—Reconciliation of EBITDA to Net Income by Segment" for reconciliations of EBITDA to net income on a segment basis.

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

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

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

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

	Total	6.2	8.2

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

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

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

	Total revenues	$	247.8	$	339.6

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

	Total revenues	$	45.4	$	53.4

	Coal revenues per ton	$	33.72	$	37.34	$	3.62		10.7	%
Other
	Coal revenues	$	6.2	$	8.0
	Freight and handling revenues		1.3		1.7
	Other revenues		0.1		0.8

	Total revenues	$	7.6	$	10.5

	Coal revenues per ton	$	29.02	$	30.26	$	1.24		4.3	%
Total
	Coal revenues	$	294.3	$	394.1
	Freight and handling revenues		2.8		4.1
	Other revenues		3.7		5.3

	Total revenues	$	300.8	$	403.5

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

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

Our total revenues for the year ended December 31, 2007 were $403.5 million as compared to $300.8 million for the nine months ended December 31, 2006. Our coal revenues were $394.1 million for the year ended December 31, 2007 as compared to $294.2 million for the nine months ended December 31, 2006, primarily due to additional 2.0 million tons of coal sold for the year ended December 31, 2007, as a result of higher demand for coal in the regions in which we operate and the additional three months of operations. Coal revenues per ton increased by 2.1% to $48.30 for the year ended December 31, 2007 from $47.31 for the nine months ended December 31, 2006, primarily as a result of favorable quality adjustments for coal sold that was above the specification under the supply contracts and improved market prices. For our Central Appalachia segment, coal revenues were $337.4 million for the year ended December 31, 2007 as compared to $246.4 million for the nine months ended December 31, 2006. The greater coal revenues in 2007 in Central Appalachia were due in part to an increase in tons of coal sold, including the sale of 1.0 million tons of purchased coal and the sale of 0.1 million tons of coal from our inventory. For our Northern Appalachia segment, coal revenues were $48.7 million for the year ended December 31, 2007 as compared to $41.7 million for the nine months ended December 31, 2006. These greater coal revenues were primarily due to higher coal revenues per ton in Northern Appalachia, which increased by $3.62, or 10.7%, to $37.34 from $33.72 for the nine months ended December 31, 2006. For our Other segment, coal revenues were

$8.0 million for the year ended December 31, 2007, as compared to $6.2 million for the nine months ended December 31, 2006. These greater coal revenues were due to additional production from our Colorado operations as well as the additional three months of operations. Coal revenues per ton for our Other segment also increased, to $30.26 for the year ended December 31, 2007 from $29.02 per ton for the nine months ended December 31, 2006.

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

		Nine Months Ended December 31, 2006				Increase (Decrease)
				Year Ended December 31, 2007		Increase (Decrease)
Segment				Year Ended December 31, 2007		Dollars			%*
		(in millions, except per ton data and %)
Central Appalachia
	Cost of operations (exclusive of depreciation, depletion and amortization shown separately below)	$	200.4	$	272.8
	Freight and handling costs		0.1		1.2
	Depreciation, depletion and amortization		24.6		24.5
	Selling, general and administrative		13.9		11.2
	Cost of operations per ton	$	41.98	$	41.40	$	(0.58	)	(1.4	)%
Northern Appalachia
	Cost of operations (exclusive of depreciation, depletion and amortization shown separately below)	$	29.6	$	34.0
	Freight and handling costs		1.4		1.2
	Depreciation, depletion and amortization		3.1		4.2
	Selling, general and administrative		3.7		3.0
	Cost of operations per ton	$	23.91	$	26.08	$	2.18		9.1	%
Other
	Cost of operations (exclusive of depreciation, depletion and amortization shown separately below)	$	8.2	$	11.6
	Freight and handling costs		1.3		1.7
	Depreciation, depletion and amortization		0.8		2.1
	Selling, general and administrative		0.9		1.2
	Cost of operations per ton	$	38.68	$	44.04	$	5.36		13.9	%
Total
	Cost of operations (exclusive of depreciation, depletion and amortization shown separately below)	$	238.2	$	318.5
	Freight and handling costs		2.8		4.0
	Depreciation, depletion and amortization		28.5		30.8
	Selling, general and administrative		18.6		15.4
	Cost of operations per ton	$	38.28	$	39.04	$	0.76		2.0	%

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

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

In our Central Appalachia segment, our cost of operations per ton decreased by $0.58, or 1.4%, to $41.40 per ton for the year ended December 31, 2007 from $41.98 per ton for the nine months ended December 31, 2006. The decrease was primarily due to lower costs for outside services, maintenance and trucking, which decreased by $0.78, $0.21 and $0.62 per ton, respectively. This decrease was offset by increases in royalty, operating supplies and labor costs, which were greater by $0.70, $0.32 and $0.28 per ton, respectively, for the year ended December 31, 2007. We produced 7.1 million tons of coal but sold 1.0 million tons of purchased coal and sold 0.1 million tons of coal from our inventory for the year ended December 31, 2007 as compared to producing and selling 6.2 million tons of coal for the nine months ended December 31, 2006.

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

In our Other segment, our cost of operations was $11.6 million for the year ended December 31, 2007 as compared to $8.2 million for the nine months ended December 31, 2006. This increase was primarily due to costs of operations in our ancillary businesses.

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

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

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

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

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

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

Segment		Nine Months Ended December 31, 2006			Year Ended December 31, 2007
		(in millions)
Central Appalachia		$	(0.2	)	$	23.1
Northern Appalachia			5.2			9.1
Other			(1.9	)		(1.4	)

	Total	$	3.1		$	30.7

For the year ended December 31, 2007, total net income was $30.7 million as compared to $3.1 million for the nine months ended December 31, 2006. This higher income was due to the three additional months of operations, as well as higher coal sales, lower SG&A expense, lower DD&A expense, lower interest and income tax expenses, gains on sales of assets and on the retirement of advance royalties. In addition, in October 2006, our lease for the Bolt field in West Virginia was cancelled resulting in a write-off of $2.1 million. In February 2008, we re-entered into a lease with respect to our Bolt field. For our Central Appalachia segment, net income was $23.1 million for the year ended December 31, 2007 as compared to a net loss of $0.2 million for the nine months ended December 31, 2006. Net income in our Northern Appalachia segment was also greater for the year ended December 31, 2007, at $9.1 million as compared to $5.2 million for the nine months ended December 31, 2006, primarily due to greater coal revenues. Net loss in our Other segment was $1.4 million for the year ended December 31, 2007 as compared to $1.9 million for the nine months ended December 31, 2006.

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

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

	Total	$	38.2		$	66.9

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

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

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

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

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

	Total	7.9	6.2

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

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

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

	Total revenues	$	307.1	$	247.8

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

	Total revenues	$	48.9	$	45.4

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

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

	Total revenues	$	7.9	$	7.6

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

	Total revenues	$	364.0	$	300.8

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

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

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

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

		Year Ended March 31, 2006		Nine Months Ended December 31, 2006		Increase (Decrease)
Segment						Increase (Decrease)
Segment						Dollars			%^*
		(in millions, except per ton data and %)
Central Appalachia
	Cost of operations (exclusive of depreciation, depletion and amortization shown separately below)	$	249.1	$	200.4
	Freight and handling costs		1.6		0.1
	Depreciation, depletion and amortization		11.0		24.6
	Selling, general and administrative		13.1		13.9
	Cost of operations per ton	$	39.77	$	41.98	$	2.22		5.6	%
Northern Appalachia
	Cost of operations (exclusive of depreciation, depletion and amortization shown separately below)	$	35.0	$	29.6
	Freight and handling costs		3.4		1.4
	Depreciation, depletion and amortization		2.5		3.1
	Selling, general and administrative		3.3		3.7
	Cost of operations per ton	$	25.14	$	23.91	$	(1.23	)	(4.9	)%
Other
	Cost of operations (exclusive of depreciation, depletion and amortization shown separately below)	$	7.4	$	8.2
	Freight and handling costs		1.4		1.3
	Depreciation, depletion and amortization		0.3		0.8
	Selling, general and administrative		0.7		0.9
	Cost of operations per ton	$	30.07	$	38.68	$	8.61		28.6	%
Total
	Cost of operations (exclusive of depreciation, depletion and amortization shown separately below)	$	291.5	$	238.2
	Freight and handling costs		6.3		2.8
	Depreciation, depletion and amortization		13.8		28.5
	Selling, general and administrative		17.1		18.5
	Cost of operations per ton	$	36.89	$	38.28	$	1.39		3.8	%

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

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

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

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

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

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

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

Depreciation, Depletion and Amortization. Total DD&A expense was $28.5 for the nine months ended December 31, 2006, million as compared to $13.8 million for the year ended March 31, 2006. This increase in DD&A expense was due to additional amortization of $5.5 million for development costs related to our Central Appalachia and Colorado operations, $4.6 million of additional deferred coal sales from the prior accounting period and $4.3 million of additional depletion.

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

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

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

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

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

	Total	$	31.7	$	3.1

Total net income was $3.1 million for the nine months ended December 31, 2006 as compared to $31.7 million for the year ended March 31, 2006. The lower net income was partially due to the three fewer months of operations. In addition, in October 2006, our lease for the Bolt field in West Virginia was cancelled, resulting in a write-off of $2.1 million. Net income was also adversely impacted by increases in DD&A expense of $14.7 million and SG&A expense of $1.5 million.

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

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

	Total	$	50.5	$	38.2

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

Reconciliation of EBITDA to Net Income by Segment

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

Year Ended March 31, 2006		Central Appalachia		Northern Appalachia		Other		Total
		(in millions)
Net income		$	29.0	$	2.7	$	—	$	31.7
Plus:
	Depreciation, depletion and amortization		11.0		2.5		0.3		13.8
	Interest expense		4.2		0.6		0.2		5.0
	Income tax expense		0.1		—		—		0.1

EBITDA		$	44.3	$	5.8	$	0.4	$	50.5

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

EBITDA		$	29.1		$	9.3	$	(0.3	)	$	38.2

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

EBITDA		$	42.7	$	11.6	$	(0.6	)	$	53.7

Year Ended December 31, 2007		Central Appalachia			Northern Appalachia		Other			Total
		(in millions)
Net income (loss)		$	23.1		$	9.1	$	(1.4	)	$	30.7
Plus:
	Depreciation, depletion and amortization		24.5			4.2		2.1			30.8
	Interest expense		4.1			0.8		0.6			5.6
	Income tax (benefit)		(0.1	)		—		—			(0.1	)

EBITDA		$	51.6		$	14.0	$	1.3		$	66.9

Liquidity and Capital Resources

Liquidity

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

The principal indicators of our liquidity are our cash on hand and availability under our credit facility. As of December 31, 2007, our available liquidity was $41.1 million, including cash on hand of $3.5 million and $37.6 million available under our credit facility.

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

Cash Flows

Year Ended December 31, 2007 Compared to the Nine Months Ended December 31, 2006. Net cash provided by operating activities was $52.5 million for the year ended December 31, 2007 as compared to $36.9 million for the nine months ended December 31, 2006. This greater amount was due to a greater net income of $27.7 million, which was offset by greater net operating assets and liabilities of $9.7 million and greater non-cash charges of $2.4 million. Net income for the year ended December 31, 2007 was $27.7 million greater, as compared to the nine months ended December 31, 2006, primarily as a result of coal revenues per ton that were higher by $0.99 and the sale of 1.0 million tons of purchased coal. Our interest expense was also $0.9 million lower for the year ended December 31, 2007.

For the year ended December 31, 2007, net cash used in investing activities was $28.1 million as compared to $28.8 million for the nine months ended December 31, 2006. We invested cash of $32.8 million in mining equipment and coal properties for the year ended December 31, 2007 as compared to $32.7 million for the nine months ended December 31, 2006. Proceeds from the sales of

assets were $4.5 million for the year ended December 31, 2007 as compared to $0.4 million for the nine months ended December 31, 2007 due to the sale of certain excess equipment during 2007. We received $0.3 million as payment on notes receivables during the year ended December 31, 2007 as compared to $2.0 million during the nine months ended December 31, 2006.

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

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

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

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

Contractual Obligations

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

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

	Total	$	147,382	$	36,043	$	16,484	$	74,997	$	19,858

(1): Assumes a current LIBOR of 5.20% plus the applicable margin, which remains constant for all periods.

(2): Some of our surface mining equipment and a coal handling and loading facility are categorized as operating leases. These leases have maturity dates ranging from one month to five years.
(3): We have obligations on various coal and land leases to prepay certain amounts which are recoupable in future years when mining occurs.

Capital Expenditures

Our mining operations require investments to expand, upgrade or enhance existing operations and to meet environmental and safety regulations. Our capital requirements primarily consist of maintenance and replacement capital expenditures and expansion capital expenditures. Maintenance and replacement capital expenditures are those capital expenditures required to maintain or replace our capital asset base. Expansion capital expenditures are those capital expenditures made to increase or expand the size of our capital asset base. Examples of maintenance and replacement capital expenditures include 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 incurred to maintain or replace our capital asset base. 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 incurred to increase or expand our capital asset base.

For the year ending December 31, 2008, we have budgeted $47.3 million in capital expenditures of which $33.0 million represents maintenance and replacement capital expenditures and $14.3 million represents expansion capital expenditures. We expect to fund maintenance and replacement capital expenditures primarily from cash generated by our operations and expansion capital expenditures with borrowings under our credit facility, other external sources of financings or cash generated from operations.

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

Off-Balance Sheet Arrangements

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

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

As of December 31, 2007, we had $18.4 million in letters of credit outstanding, of which $15.0 million served as collateral for surety bonds.

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Credit Facility

Our $200.0 million credit facility is available to repay indebtedness as well as for general business purposes, including working capital, capital expenditures, acquisitions, and may be increased by up to $75.0 million with the consent of the lenders, so long as there is no event of default. Of the $200.0 million, $50.0 million is available for letters of credit. We expect to amend our credit agreement in connection with the closing of this offering to provide a sub-facility of $15.0 million that will be available for distributions. We expect that the $15.0 million distribution sub-facility will be subject to an annual "clean-down" period of at least 15 consecutive days in which the amount outstanding under the distribution sub-facility is reduced to $0.

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 our subsidiaries.

Our credit facility bears interest at either (1) LIBOR plus 1.25% to 1.75% per annum, depending on our leverage ratio, or (2) a base rate that is the higher of the prime rate or the federal funds rate plus 0.50%. We incur letter of credit fees equal to the then applicable spread above LIBOR on the undrawn face amount of standby letters of credit issued and a 15 basis point fronting fee payable to the administrative agent on the aggregate face amount of such letters of credit. In addition, we incur a commitment fee on the unused portion of the credit facility at a rate of 0.25% per annum based on the unused portion of the facility. The credit facility will mature in 2013. At that time, the credit agreement will terminate and all outstanding amounts thereunder will be due and payable, unless the credit agreement is amended.

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

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

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

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

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

•: failure to pay principal, interest or any other amount when due;

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

As of December 31, 2007, we had borrowings outstanding under our credit facility of approximately $69.0 million.

Impact of Inflation

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

Critical Accounting Policies and Estimates

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

Revenue Recognition

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

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

Other revenues consist of limestone sales, coal handling, royalties, contract mining and rental income. With respect to other revenues recognized in situations unrelated to the shipment of coal, we carefully review the facts and circumstances of each transaction and apply the relevant accounting literature as appropriate, and do not recognize revenue until the following criteria are met: persuasive evidence of an arrangement exists; delivery has occurred or services have been rendered; the seller's price to the buyer is fixed or determinable; and collectibility is reasonably assured. Advance payments received are deferred and recognized in revenue as coal is shipped or rental income is earned.

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Reserves and Non-Reserve Deposits

Marshall Miller & Associates, Inc. ("Marshall Miller") prepared a detailed study of our coal reserves and non-reserve coal deposits as of October 31, 2007 (except for information regarding the Deane mining complex, which is as of the acquisition date, February 8, 2008; the Bolt field, which is as of the lease date, February 15, 2008; and the Sands Hill mining complex, which is as of the acquisition date, December 14, 2007) based on all of our geologic information, including our updated drilling and mining data. The study conducted by Marshall Miller was planned and performed to obtain reasonable assurance of our subject demonstrated reserves and non-reserve coal deposits. In connection with the study, Marshall Miller prepared maps and had certified professional geologists develop estimates based on data supplied by us and using standards accepted by government and industry.

Based on the Marshall Miller study and the foregoing assumptions and qualifications, we estimate that, as of October 31, 2007 (except for information regarding the Deane mining complex, which is as of the acquisition date, February 8, 2008; the Bolt field, which is as of the lease date, February 15, 2008; and the Sands Hill mining complex, which is as of the acquisition date, December 14, 2007), we owned or leased 256.2 million tons of proven and probable coal reserves and 126.5 million tons of non-reserve coal deposits. Please read "Business—Coal Reserves and Non-Reserve Coal Deposits."

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

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

Reclamation

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

•: Discount rate. SFAS No. 143 requires that asset retirement obligations be recorded at fair value. In accordance with the provisions of SFAS No. 143, we utilize discounted cash flow techniques to estimate the fair value of our obligations. We base our discount rate on the rates of treasury bonds with maturities similar to expected mine lives, adjusted for our credit standing.

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•: Third-party margin. SFAS No. 143 requires the measurement of an obligation to be based upon the amount a third-party would demand to assume the obligation. Because we plan to perform a significant amount of the reclamation activities with internal resources, a third-party margin was added to the estimated costs of these activities. This margin was estimated based upon our historical experience with contractors performing certain types of reclamation activities. The inclusion of this margin will result in a recorded obligation that is greater than our estimates of our cost to perform the reclamation activities. If our cost estimates are accurate, the excess of the recorded obligation over the cost incurred to perform the work will be recorded as a gain at the time that reclamation work is completed.

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

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

Property, Plant and Equipment

Property, plant and equipment, including coal properties, mine development costs and construction costs, are recorded at cost, which includes construction overhead and interest, where applicable. Expenditures for major renewals and betterments are capitalized while expenditures for maintenance and repairs are expensed as incurred.

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

Any uncertainty surrounding the application of the depletion policy is directly related to the assumptions as to the number of recoverable tons contained in a particular coal land area. The amount of compensation paid for the coal lands is a set amount; however, the "recoverable tons" contained in the coal land area are based on third party engineering estimates, which can and often do change as the tons are mined. Any change in the number of "recoverable tons" contained in a coal land area will result in a change in the depletion rate and corresponding depletion expense. For the year ended December 31, 2007, we recorded $3.6 million of depletion expense. Assuming that "recoverable tons"

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are reduced by 10%, this would result in a decrease in pre-tax income of $0.4 million. This calculation would also be applied in the case of a coal land area containing more "recoverable tons" than the original estimate. This would result in increased net income.

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

Mining and other equipment and related facilities are depreciated using the straight-line method based upon the shorter of estimated useful lives of the assets or the estimated life of each mine.

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

Asset Impairments

We follow SFAS No. 144, Accounting for the Impairment or Disposal of Long-Lived Assets ("SFAS No. 144"), which requires that projected future cash flows from use and disposition of assets be compared with the carrying amounts of those assets. When the sum of projected cash flows is less than the carrying amount, impairment losses are recognized. In determining such impairment losses, discounted cash flows are utilized to determine the fair value of the assets being evaluated. Also, in certain situations, expected mine lives are shortened because of changes to planned operations. When that occurs and it is determined that the mine's underlying costs are not recoverable in the future, reclamation and mine closing obligations are accelerated and the mine closing accrual is increased accordingly. To the extent it is determined asset carrying values will not be recoverable during a shorter mine life, a provision for such impairment is recognized. Our debt covenant ratios are based on EBITDA. A hypothetical impairment of $5.0 million to both the book and tax basis would result in additional annual federal taxes being passed through to our unitholders. We do not believe this would have a material impact on the ratio calculations.

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

Postretirement Benefits

Our Northern Appalachia segment has long and short-term liabilities for postretirement benefit cost obligations. Detailed information related to these liabilities is included in the notes to our consolidated financial statements included elsewhere in this prospectus. Liabilities for postretirement benefits are not funded. The liability is actuarially determined, and we use various actuarial assumptions, including the discount rate and future cost trends, to estimate the costs and obligations for postretirement benefits. The discount rate assumption reflects the rates available on high quality fixed income debt instruments. The discount rate used to determine the net periodic benefit cost for postretirement medical benefits was 5.6% for the six months ended June 30, 2007 and 6.25% for the six months ended December 31, 2007. We make assumptions related to future trends for medical care costs in the estimates of retiree health care and work-related injury and illness obligations. The future health care cost trend rate represents the rate at which health care costs are expected to increase over the life of the plan. The health care cost trend rate assumptions are determined primarily based upon our historical rate of change in retiree health care costs. The postretirement expense in the year ended

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December 31, 2007 was based on an assumed heath care inflationary rate of 9.0% in the operating period decreasing to 5.0% in 2016, which represents the ultimate health care cost trend rate for the remainder of the plan life. A one-percentage point increase in the assumed ultimate health care cost trend rate would increase the accumulated postretirement benefit obligation at December 31, 2007 by $0.4 million. A one-percentage point decrease in the assumed ultimate health care cost trend rate would decrease the accumulated postretirement benefit obligation at December 31, 2007 by $0.4 million. If our assumptions do not materialize as expected, actual cash expenditures and costs that we incur could differ materially from our current estimates. Moreover, regulatory changes could increase our requirement to satisfy these or additional obligations.

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

Income Taxes

Our predecessor is considered a partnership for income tax purposes. Accordingly, the members of Rhino Energy LLC reported their share of its taxable income or loss on their tax returns. The provisions for income tax consisted of state income tax for the year ended March 31, 2006 and for the nine months ended December 31, 2006. This provision was a result of the state of Kentucky instituting a law effective January 1, 2005 that required partnerships to pay state income tax. This law was rescinded on January 1, 2007, resulting in an income tax benefit for the year ended December 31, 2007. For a discussion of 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."

Recent Accounting Pronouncements

In June 2006, the Financial Accounting Standards Board ("FASB") issued Financial Interpretation No. 48, Accounting for Uncertainty in Income Taxes, an interpretation of FASB Statement No. 109 ("FIN 48"). This interpretation clarifies the accounting for uncertainty in income taxes recognized in an enterprise's financial statements in accordance with FASB Statement No. 109, Accounting for Income Taxes. Since we are not a taxable entity for federal and state income tax purposes, our adoption of FIN 48 on January 1, 2007 did not have a material impact on our consolidated financial statements.

In September 2006, the FASB issued SFAS No. 157, Fair Value Measures ("SFAS No. 157"), which establishes a framework for measuring fair value and expands disclosures about fair value measurements. Pursuant to FASB Financial Staff Position 157-2, the FASB issued a partial deferral of the implementation of SFAS No. 157 as it relates to all non-financial assets and liabilities where fair value is not already the required measurement attribute by other accounting standards. The remainder of SFAS No. 157 was effective for us on January 1, 2008. The adoption of SFAS No. 157 did not have a material impact on our financial position, results of operations or cash flows.

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

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the new measurement date is effective for fiscal years ending after December 15, 2008. We adopted the recognition and disclosure provisions of SFAS No. 158 as of December 31, 2006 on the required prospective basis.

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

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

In February 2008, the FASB Emerging Issues Task Force issued EITF Issue No. 07-04, Application of the Two-Class Method under FASB Statement No. 128, Earnings per Share, to Master Limited Partnerships ("EITF 07-04"). EITF 07-04 specifies when a master limited partnership becomes contractually obligated to make cash distributions to general partners, limited partners and holders of incentive distribution rights, for purposes of calculating earnings per unit. EITF 07-04 is effective for fiscal years beginning after December 15, 2008. We are currently evaluating the effect that the adoption of EITF 07-04 will have on the partnership's net earnings per unit.

Quantitative and Qualitative Disclosures About Market Risk

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

Commodity Price Risk

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

Some of the products used in our mining activities, such as diesel fuel, explosives and steel products for roof support used in our underground mining, are subject to price volatility. Through our suppliers, we utilize forward fuel purchases to manage the exposure related to this volatility. A hypothetical increase of $0.10 per gallon for diesel fuel would have reduced net income for the year ended December 31, 2007 by $1.0 million. A hypothetical increase of 10% in steel prices would have reduced net income for the year ended December 31, 2007 by $0.9 million. A hypothetical increase of 10% in explosives prices would have reduced net income for the year ended December 31, 2007 by $1.0 million.

Interest Rate Risk

We have exposure to changes in interest rates on our indebtedness associated with our credit facility. During the past year, we have been operating in a period of declining interest rates and we have managed to take advantage of the trend to reduce our interest expense. A hypothetical increase or decrease in interest rates by 1% would have changed our interest expense by $0.7 million for the year ended December 31, 2007.

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THE COAL INDUSTRY

Coal is an abundant, efficient and affordable natural resource used primarily to provide fuel for the generation of electric power. World-wide recoverable coal reserves are estimated to be approximately 1.0 trillion tons. According to the EIA, the United States is one of the world's largest producers of coal and has approximately 27% of global coal reserves, representing approximately 239 years of supply based on current usage rates. Coal is the most abundant fossil fuel in the United States, representing the vast majority of the nation's total fossil fuel reserves.

Recent Coal Market Conditions and Trends

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

•: Continued strong demand in the United States. Domestic demand for steam coal from the electricity generating sector, continues to be strong, driven principally by growth in electricity sales, which are expected to increase by 41% from 2005 to 2030, as estimated by the EIA;
•: Growing export market. Coal producers in the Appalachian region of the United States are benefiting from growing demand for coal in Europe, Asia and other foreign markets. Total U.S. coal exports increased by approximately 19% from 2006 to 2007, according to the EIA. In particular, exports to Europe and Brazil have increased 22% and 48%, respectively, through September 2007 as compared to the same period in 2006, as reported by the EIA;
•: Proximity of eastern U.S. coal market. Eastern U.S. coal producers are also positioned to capitalize on the current favorable export market given their geographical proximity. Eastern U.S. coal producers have access to multiple modes of transportation within the United States, but are also located close to the coast, which provides access to transoceanic shipments. The total cost to purchase and ship coal from the East Coast of the United States to Europe is currently competitive with other coal exporting regions, as freight rates from the Pacific coal supply regions have increased significantly in recent months. Shipping costs from the eastern United States to western Europe, as measured by the Panamax Coal Voyage Spot Rates from Hampton Roads (VA) to the ARA (Antwerp-Rotterdam-Amsterdam) 70,000t, have ranged between $18.56 and $43.23 per ton since 2007;
•: U.S. transportation logistics. Constraints in the U.S. transportation system continue to persist. In particular, rail bottlenecks and rail maintenance downtime in the western United States have limited the coal produced in those regions, such as the Powder River Basin, from being transported and sold in the eastern end use markets;
•: Decline in production and reserve levels. Coal production in the eastern United States continues to decline. Based on the EIA's preliminary data for 2007 and reported data for 2006, production in the Appalachian region decreased 8% from 391.2 million tons in 2006 to 360.4 million tons in 2007. Not only has production declined, but coal reserves also continue to decline in the eastern United States regions. According to the EIA, as of December 31, 2006, total coal reserves in the eastern United States are estimated to be 2,631 million tons, which is approximately 8% lower than the estimated 2,859 million tons at December 31, 2005; and
•: High prices for alternative energy sources. Coal continues to be the lowest cost source of energy relative to its substitutes. Spot prices as of December 31, 2007 for Henry Hub natural gas and

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New York Harbor No. 2 heating oil are $7.16 per million Btu and $2.64 per gallon or $19.01 per million Btu, respectively, as reported by Bloomberg L.P. and the EIA. On the other hand, Central Appalachian spot coal prices, as measured by Big Sandy Barge 12,500 Btu, <3.0 lb SO2 / MMBtu prices, reached $55.00 per ton on December 31, 2007, representing $0.6875 per million Btu.

•: Demand for coal by emerging global economies, in particular China and India, continues to increase.
•: Traditional exporters of coal to Asia and other regions around the world are challenged to meet the growing demand for coal, which is creating export opportunities for other coal producers, particularly those located in the eastern United States.
•: The continued weakness of the U.S. dollar is also improving the competitiveness of U.S. exports.
•: Flooding in Australia's central Queensland coalfields in January 2008, which disrupted its metallurgical coal production, is causing Asian countries dependent on Australian coal to source coal from other places.

Coal Pricing

Steam Coal Pricing

Steam coal prices remained relatively flat through most of the mid-to-late 1990s. When long-term contracts for many producers began to expire in 2000 and beyond, new contracts were entered into reflecting then-current market demand and operating conditions. Coal prices increased significantly between 2000 and 2006, especially in the eastern regions of the United States. During 2006, mild weather conditions across the United States led to reduced electricity demand and higher coal inventory levels, resulting in a decline in spot steam coal prices. Electricity demand went from 1,037 short tons in 2005 to 1,027 short tons in 2006, while coal production in Appalachia declined by 1.5% compared to the same period in 2005. In 2007, the pricing environment for coal, eastern U.S. coal in particular, became extremely favorable as production remained low while demand increased. This momentum in the eastern U.S. coal markets has only increased in 2008.

Metallurgical Coal Pricing

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

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the robust pricing environment, trending upward through late 2003 and into early 2008. High U.S. demand for metallurgical coal worldwide and recent international logistical issues put a strain on already tight eastern supplies.

Coal Markets

NYMEX Market

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

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

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

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

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

Over-The-Counter Market

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

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delivery of coal, calls, puts and swaps, to hedge against price exposure and minimize the risks of volatility.

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

Coal Characteristics

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

Heat Value

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

Sulfur Content

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

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

Other

Ash is the inorganic residue remaining after the combustion of coal. As with sulfur content, ash content varies from seam to seam. Ash content is an important characteristic of coal because electric generating plants must handle and dispose of ash following combustion. The absence of ash is also important to the process by which metallurgical coal is transformed into coke for use in steel

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production. Moisture content of coal varies by the type of coal and the region where it is mined. In general, high moisture content decreases the heat value and increases the weight of the coal, thereby making it more expensive to transport. Moisture content in coal, as sold, can range from approximately 5% to 30% of the coal's weight.

Coal Regions

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

Appalachian Region

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

Central Appalachia. Central Appalachia includes eastern Kentucky, Virginia and southern West Virginia. Coal from this region generally has a sulfur content of 0.7% to 1.5% and a heat value of between 10,000 and 13,500 Btu/lb. We have ten underground mines and six surface mines in Kentucky and West Virginia and, as of October 31, 2007 (except for the Deane mining complex, which is as of the acquisition date, February 8, 2008, and the Bolt field, which is as of the lease date, February 15, 2008), controlled approximately 93.3 million tons of proven and probable coal reserves and approximately 49.4 million tons of non-reserve coal deposits in Central Appalachia.

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

Interior Region

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

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

Western United States

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

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Western Bituminous Region. The Western Bituminous Region includes western Colorado and eastern Utah. The coal from this region typically has a sulfur content of 0.5% to 1.0% and a heat value of between 10,000 and 12,000 Btu/lb. In this region, as of October 31, 2007, we controlled approximately 1.5 million tons of proven and probable coal reserves. We also operate an underground mine in Colorado on property leased from the Bureau of Land Management ("BLM") under a contract mining agreement with CAM-Colorado LLC. In connection with the closing of this offering, Rhino Energy LLC will distribute its ownership interests in CAM-Colorado LLC to Wexford Funds. Please read "Certain Relationships and Related Party Transactions—Colorado Mining Agreement" and "—Shared Services Agreement."

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

U.S. Coal Production by Region

Coal is mined from coal fields throughout the United States, with the major production centers located in the western United States, Northern and Central Appalachia and the Illinois Basin. The quality of coal varies by region. U.S. coal production was approximately 1.2 billion tons in 2006 according to the EIA. The following table, derived from data prepared by the EIA, sets forth production statistics in the three coal producing regions in the United States for the periods indicated.

	Actual										Projected						Compounded Annual Growth Rate
	2002		2003		2004		2005		2006		2010		2020		2030		2006-2010		2006-2030
	(in million tons)
Total Tons:
Appalachian Region	396		376		391		397		391		381		348		373		(0.6	)%	(0.2	)%
Interior Region	147		146		146		149		151		171		203		247		3.2	%	2.1	%
Western United States	550		549		575		585		620		637		772		1,072		0.7	%	2.3	%

Total	1,093		1,071		1,112		1,131		1,162		1,189		1,323		1,692		0.6	%	1.6	%

Percentage of Total Tons:
Appalachian Region	36	%	35	%	35	%	35	%	34	%	32	%	26	%	22	%
Interior Region	14	%	14	%	13	%	13	%	13	%	14	%	16	%	15	%
Western United States	50	%	51	%	52	%	52	%	53	%	24	%	58	%	63	%

Demand for U.S. Coal Production

Coal is primarily consumed by utilities to generate electricity. It is also used by steel companies to make steel products and by a variety of industrial users to heat and power foundries, cement plants, paper mills, chemical plants and other manufacturing and processing facilities. In general, coal is characterized by end use as either steam coal or metallurgical coal. Steam coal is used by electricity generators and by industrial facilities to produce steam, electricity or both. Metallurgical coal is refined into coke, which is used in the production of steel. Over the past quarter century, total coal consumption in the United States has nearly doubled to approximately 1.2 billion tons in 2006. The growth in the demand for coal has coincided with an increased demand for coal from electric power generators.

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

	Actual					Projected			Compounded Annual Growth Rate
	2002	2003	2004	2005	2006	2010	2020	2030	2006-2010		2006-2030
	(in million short tons)
Electrical Generation	978	1,005	1,016	1,037	1,027	1,104	1,262	1,570	1.8	%	1.8	%
Industrial	61	62	61	60	59	64	63	64	2.1	%	0.3	%
Steel Production	24	24	24	23	23	22	21	21	(1.1	)%	(0.4	)%
Residential/Commercial	4	4	5	5	3	5	5	5	13.6	%	2.2	%
Coal to Liquids	—	—	—	—	—	—	26	112	n/a		n/a
Export	40	43	48	50	50	44	31	27	(3.1	)%	(2.5	)%

Total	1,107	1,138	1,154	1,175	1,162	1,239	1,408	1,799	1.6	%	1.8	%

The nation's power generation infrastructure is approximately 50.4% coal-fired. As a result, coal has consistently maintained approximately a 49% to 53% market share during the past 10 years, principally because of its relatively low cost, reliability and abundance. Coal is the lowest cost fossil-fuel used for base-load electric power generation, being considerably less expensive than natural gas or fuel oil. Coal-fired generation is also competitive with nuclear power generation especially on a total cost per megawatt-hour basis. The production of electricity from existing hydroelectric facilities is inexpensive, but its application is limited both by geography and susceptibility to seasonal and climatic conditions. In 2006, non-hydropower renewable power generation accounted for only 2.4% of all the electricity generated in the United States, of which wind power—the alternative fuel sources that provides some of the greatest environmental benefits—represented only 0.7% of U.S. power generation and are generally not economically competitive with existing technologies.

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

The following chart sets forth the source fuel for net electricity generation for 2006, according to the EIA.

Electricity Generation Source		% of Total Electricity Generation
Coal		50.4	%
Nuclear		20.1	%
Natural Gas		18.8	%
Hydro		7.2	%
Petroleum and Other		3.5	%

	Total	100.0	%

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

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

	Actual		Projected
Electric Generation Type	2006		2010		2020		2030
	(per million Btu)
Petroleum Products	$	6.23	$	7.91	$	7.08	$	7.96
Natural Gas	$	6.94	$	6.22	$	5.76	$	6.33
Coal	$	1.68	$	1.71	$	1.58	$	1.69

Mining Methods

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

Underground Mining

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

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

Surface Mining

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

Surface-mining methods include area, contour, highwall and mountaintop removal. Area mines are surface mines that remove shallow coal over a broad area where the land is fairly flat. After the coal has been removed, the overburden is placed back into the pit. Contour mines are surface mines that mine coal in steep, hilly, or mountainous terrain. A wedge of overburden is removed along the coal outcrop on the side of a hill, forming a bench at the level of the coal. After the coal is removed, the

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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, railroads account for nearly 75% of total U.S. coal shipments, while truck movements account for an additional 12%. Trucks and overland conveyors haul coal over shorter distances, while barges, Great Lake carriers and ocean vessels move coal to export markets and domestic markets requiring shipment over the Great Lakes. Most coal mines are served by a single rail company, but much of the Powder River Basin is served by two competing rail carriers, the Burlington Northern Santa Fe Railway and the Union Pacific Railroad. Rail competition in this major coal-producing region is important because rail costs constitute a significant portion of the delivered cost of Powder River Basin coal in eastern markets.

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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 have a geographically diverse asset base, with coal reserves located in Central Appalachia, Northern Appalachia, the Illinois Basin and Colorado. For the year ended December 31, 2007, we produced approximately 7.1 million tons of coal and sold approximately 8.2 million tons of coal. As of October 31, 2007, we controlled approximately 222.3 million tons of proven and probable coal reserves and approximately 97.8 million tons of non-reserve coal deposits. We completed the acquisitions of the Sands Hill mining complex located in Northern Appalachia in December 2007 and the Deane mining complex located in Central Appalachia in February 2008 and entered into a lease with respect to the Bolt field located in Central Appalachia in February 2008, which together added a total of approximately 33.9 million tons of proven and probable coal reserves and approximately 28.7 million tons of non-reserve coal deposits. We expect to produce approximately 1.8 million tons of coal in 2009 from our recently acquired mining complexes. We produce high quality coal that is sold in both the steam and metallurgical coal markets. We market our steam coal primarily to electric utilities, the majority of which are rated investment grade. The metallurgical coal that we produce is sold for end use by domestic and international steel producers.

In addition, we have successfully grown our production through internal development projects. For example, we invested approximately $19.0 million in 2005 in the Hopedale mine located in Northern Appalachia to develop the approximately 17.1 million tons of proven and probable coal reserves at the mine. In 2007, the Hopedale mine produced approximately 1.3 million tons of coal. In 2007, we completed development of a new underground metallurgical coal mine at the Rob Fork mining complex located in Central Appalachia. The mine produced approximately 650,000 tons of coal for the year ended December 31, 2007. We also control proven and probable coal reserves that are currently undeveloped of approximately (1) 102.4 million tons in the Taylorville field located in the Illinois Basin, (2) 16.7 million tons in the Leesville field located in Northern Appalachia, (3) 15.3 million tons in the Bolt field and (4) 13.8 million tons in the Springdale field located in Northern Appalachia. These reserves can be developed and produced over time as industry and regional conditions permit. We believe our existing asset base will continue to provide attractive internal growth projects.

We believe our sponsor, Wexford, an SEC registered investment advisor with approximately $7.0 billion of assets under management, will provide us with access to potential acquisitions. After this offering, Wexford will control approximately 19.3 million tons of proven and probable coal reserves in Colorado. We believe that Wexford will develop these reserves, including applying for permits and developing the infrastructure necessary for mining these reserves, and will also seek to acquire substantial adjacent coal reserves. If Wexford is successful in developing these coal reserves and acquiring additional reserves, we expect that Wexford may offer these assets to us in the future. However, we cannot assure you that these assets or any other assets that Wexford owns will be offered to, or purchased by, us or on terms favorable to us. Please read "—Our Sponsor."

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	Production for the Year Ended December 31, 2007	As of October 31, 2007(1)
Region	Production for the Year Ended December 31, 2007	Proven & Provable Reserves	Average Heat Value	Average Sulfur Content	Type of Mines	Steam/ Metallurgical Reserves	Transpor- tation(2)
	(in million tons)	(in million tons)	(Btu/lb)	(%)		(in million tons)
Central Appalachia
Tug River Complex (KY, WV)	2.3	36.3	12,808	1.23	Underground and Surface	32.8/3.5	Truck, Barge, Rail (NS)
Rob Fork Complex (KY)	3.3	34.5	12,832	1.08	Underground and Surface	25.7/8.8	Truck, Barge, Rail (CSX)
Deane Complex (KY)(1)	n/a	7.2	13,196	1.55	Underground	7.2/—	Rail (CSX)
Bolt Field (WV)(1)	n/a	15.3	14,094	0.57	Underground	15.3/—	Rail (CSX)
Northern Appalachia
Hopedale Complex (OH)	1.3	17.1	13,026	2.18	Underground	17.1/—	Truck, Barge, Rail (OHC)
Sands Hill Complex (OH)(1)	<0.1	11.4	11,830	6.03	Surface	11.4/—	Truck, Barge
Leesville Field (OH)	—	16.7	13,152	2.21	Underground	16.7/—	Rail (OHC)
Springdale Field (PA)	—	13.8	13,443	1.72	Underground	13.8/—	Barge
Illinois Basin
Taylorville Field (IL)	—	102.4	12,084	3.83	Underground	102.4/—	Rail (NS)
Colorado
McClane Canyon Mine (CO)	0.2	1.5	11,522	0.57	Underground	1.5/—	Truck

Total	7.1	256.2

(1): Information regarding the Deane mining complex is as of the acquisition date, February 8, 2008; the Bolt field is as of the lease date, February 15, 2008; and the Sands Hill mining complex is as of the acquisition date, December 14, 2007. Excludes information regarding approximately 19.3 million tons of proven and probable coal reserves in Colorado to be controlled by Wexford after this offering.
(2): NS = Norfolk Southern Railroad; CSX = CSX Railroad; OHC = Ohio Central Railroad.

Business Strategies

Our primary business objective is to increase cash available for distribution by continuing to execute the following strategies:

•: Maximize profitability and maintain stable cash flows. We intend to maximize profitability and maintain stable cash flows by focusing on (1) improving the efficiency of our operations, (2) maximizing our revenue, including by entering into short-term and longer-term sales commitments with third parties that have a strong credit profile, and (3) managing our costs. We continually maintain our equipment and monitor our reserve plans to ensure we are prudently producing the maximum quantity of high quality coal from our mines. We have sales commitments for the majority of our estimated coal production for 2008 and 2009. We believe our short-term and longer-term sales commitments provide us with a reliable revenue base in the near term, while at the same time our uncommitted position enables us to sell coal in the current strong coal pricing market environment. We will also continue to manage our cost structure, which will include further vertical integration of substantially all of our trucking, reclamation, drilling and blasting activities.
•: Grow our business through internal development opportunities. A significant portion of our proven and probable coal reserves and our non-reserve coal deposits are located in the vicinity of our existing infrastructure. We believe that such proximity to our existing operations provides a number of opportunities to develop these reserves and non-reserve coal deposits without significant capital expenditures necessary to develop or expand our infrastructure. In addition, our existing base of proven and probable coal reserves includes development opportunities that

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will involve infrastructure development such as our Bolt field in West Virginia (15.3 million tons in proven and probable coal reserves), our Leesville field in Ohio (16.7 million tons in proven and probable coal reserves), our Springdale field in Pennsylvania (13.8 million tons in proven and probable coal reserves) and our Taylorville field in Illinois (102.4 million tons in proven and probable coal reserves). We have and will continue to maintain an aggressive program of systematically exploring the development of our proven and probable coal reserves as well as our non-reserve coal deposits, including the acquisition of necessary mining rights, and to deploy capital necessary to develop these coal reserves and non-reserve coal deposits to take advantage of internal development opportunities.

•: Selectively expand our operations through strategic acquisitions. Since our predecessor's inception in April 2003, we have grown through a series of strategic acquisitions of mining operations, reserves and infrastructure. We will continue to pursue strategic and accretive acquisitions of such assets both within our existing areas of operations and in new geographic areas. We also intend to further leverage our infrastructure by acquiring coal properties in close proximity to our current operations to (1) extend the lives of our mines, (2) maximize the efficiencies of our coal processing and distribution infrastructure and (3) provide us opportunities for new mine development. In addition, we intend to evaluate selected stable, cash generating coal and non-coal natural resource assets that we or our sponsor have substantial experience in identifying, acquiring at attractive valuations and operating efficiently.
•: Focus on excellence in safety and environmental stewardship. We intend to maintain our recognized leadership in mining in a safe and prudent manner. For the year ended December 31, 2007, our nonfatal days lost incidence rate for our operations was 34.2% below the industry average. For the year ended December 31, 2007, our operations received 57.1% fewer violations per inspection day than the national average according to the MSHA. We will continue to implement safety measures that are designed to promote safe operating practices and to emphasize environmental stewardship to our employees. We believe our ability to minimize lost-time injuries and environmental violations will increase our operating efficiency which will directly improve our cost structure and financial performance and also bolster employee morale.

Competitive Strengths

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

•: We have an attractive blend of short-term and longer-term sales contracts as well as uncommitted coal to sell on the spot market. As of December 31, 2007, we had sales commitments for 84%, 43% and 16% of our estimated coal production of approximately 8.6 million tons, 8.5 million tons and 9.3 million tons for the years ending December 31, 2008, 2009 and 2010, respectively. We believe our short-term and longer-term sales commitments provide us with a reliable revenue base in the near term, while at the same time our uncommitted position enables us to sell coal in the current strong coal pricing market environment.
•: We have significant internal expansion opportunities. We believe that our undeveloped proven and probable coal reserves and our non-reserve coal deposits will allow us to significantly expand production on a capital efficient basis through the utilization of our existing infrastructure, as some of these reserves and non-reserve coal deposits are located in close proximity to our existing operations. For example, in 2007 in an effort to supplement and enhance production at our Rob Fork mining complex, we completed development of a new underground metallurgical coal mine. Our investment of approximately $30.0 million included a conveyor belt to transfer coal from the mine portal directly to the preparation plant as well as an extensive entry system

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to access the main reserve body. The mine produced approximately 650,000 tons of coal for the year ended December 31, 2007. We also control proven and probable coal reserves that are currently undeveloped of approximately (1) 102.4 million tons in the Taylorville field located in the Illinois Basin, (2) 16.7 million tons in the Leesville field located in Northern Appalachia, (3) 15.3 million tons in the Bolt field located in Central Appalachia and (4) 13.8 million tons in the Springdale field located in Northern Appalachia. These reserves can be developed and produced over time as industry and regional conditions permit.

•: We have a proven track record of successful acquisitions. Since our predecessor's inception in 2003, we have completed numerous asset acquisitions with a total purchase price of approximately $173.9 million. Through these acquisitions and other coal lease transactions we have significantly increased our proven and probable coal reserves and non-reserve coal deposits. The members of our senior management team have, on average, 24 years of coal industry and related experience and have a demonstrated track record of acquiring, building and operating coal businesses profitably and safely throughout the United States. The acquisitions consummated by our management team have consisted of high quality coal reserves and union-free operations, with limited reclamation and legacy liabilities. We believe we have a disciplined acquisition strategy that is focused on acquiring selected assets at attractive valuations, while limiting to the extent possible the assumption of debt and reclamation and employee-related liabilities.
•: Our mining activities are strategically located. Our mining operations are located near many major power plants and on or near coal-hauling railroads in the eastern United States, including the CSX Rail, the NS Rail and the OHC Rail. Additionally, certain of our mines are located within economical trucking distance to the Big Sandy River and/or the Ohio River where coal can be transported by barge. Cost and availability of transportation are critical marketing factors because our customers generally pay the transportation costs for the delivery of coal, and these costs represent a significant portion of a customer's total cost of delivered coal. We believe the geographic location of our mines and the multiple transportation options available to us provide us with a transportation cost advantage compared to many of our competitors.
•: We offer a variety of high quality steam and metallurgical coal that meets our customers' needs. Our customers and end users, which include electric utilities in the United States and domestic and international steel producers, demand a variety of coal types and characteristics. The majority of our steam coal production in Central Appalachia also meets the specifications of both the OTC and NYMEX markets. In addition, the substantial planned increase in the number of electrical generating plants utilizing pollution control devices has created and we expect will continue to create an expanding market for the coal that we produce in Central and Northern Appalachia.
•: We have vertically integrated many of our operations to control operating costs. We have recently vertically integrated substantially all of our trucking, reclamation and drilling and blasting activities. The integration of these activities has lowered our cost and significantly lessened our dependence on certain third-party service providers. The vertical integration helps us to maintain our low cost structure and maximize profitability.
•: We have a strong credit profile. As a result of our prudent acquisition strategy and conservative financial management, we believe that our capital structure after this offering will provide us significant financial flexibility to pursue our strategic goals, including (1) pursuing acquisitions, (2) investing in our existing operations and (3) managing our operations through periods of difficult coal market conditions. We believe that compared to other publicly traded U.S. coal producers, we have relatively low levels of outstanding debt, legacy liabilities, reclamation liabilities and postretirement employee obligations. In addition, we sell a majority of our coal to a number of customers with an investment-grade credit rating.

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•: We have an experienced and dedicated sponsor. Wexford, our sponsor, manages over $7.0 billion of investments and has extensive experience in numerous segments across the energy sector, including the acquisition and operation of coal, oil and natural gas assets. Wexford will continue to own a substantial equity position in us consisting of an 84.6% limited partner interest, a 2% general partner interest and the incentive distribution rights. We have limited the maximum level of distributions of available cash on our incentive distribution rights to 10.0%, which is significantly lower than levels of many of the other publicly traded partnerships, which have maximum levels set at 50.0%. We believe our relationship with our sponsor will help us to grow our coal operations and potentially acquire selected coal and non-coal natural resource assets in the future. Please read "—Our Sponsor."

Our History

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

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

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

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

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

In April 2004, we also acquired coal assets from subsidiaries of American Electric Power Company, Inc., AEP Coal, Inc. and certain of its affiliates ("AEP") in eastern Kentucky, Ohio and Pennsylvania. In this transaction, we acquired only active mining areas and did not assume any legacy liabilities related to AEP's inactive mining areas. The acquisition included approximately 18.4 million tons of surface and underground proven and probable coal reserves and approximately 11.5 million

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tons of non-reserve coal deposits in Kentucky and approximately 50.0 million tons of underground proven and probable coal reserves and approximately 43.7 million tons of non-reserve coal deposits in Ohio and Pennsylvania and a substantial amount of infrastructure. In Kentucky, this infrastructure included the Rob Fork preparation plant and unit loadout facility on the CSX Rail and six underground mines and two surface mines, collectively referred to as the Rob Fork mining complex. The Ohio assets included an underground mine that was mined out in 2007, and the Nelms preparation plant near Cadiz, Ohio. The Ohio assets also included the Hopedale mine which was shut in the 1980s and subsequently reopened by us in September 2005. The Hopedale mine has approximately 17.1 million tons of underground proven and probable coal reserves and approximately 23.2 million tons of non-reserve coal deposits and an expected reserve life of at least ten years at its planned production rate.

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

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

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

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

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

In February 2008, we acquired approximately 30 acres containing approximately 7.2 million tons of proven and probable coal reserves and approximately 0.2 million tons of non-reserve coal deposits located in Letcher, Pike and Knott Counties in Kentucky from CONSOL of Kentucky, Inc. In addition, the acquisition included approximately 14,627 acres of surface property, as well as a 950 tons-per-hour preparation plant and unit train loadout facility on the CSX Rail.

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

Our Sponsor

Rhino Energy LLC, our predecessor, was formed in 2003 by entities managed by Wexford, an SEC registered investment advisor with over $7.0 billion of assets under management. Upon the consummation of this offering, Wexford Funds will own an 84.6% limited partner interest, and the Wexford Principals will own 100% of the ownership interests of our general partner. Our general partner will maintain its 2% general partner interest in us. We will also issue to our general partner the incentive distribution rights, which entitle the holder to increasing percentages, up to a maximum of 10% of the cash we distribute in excess of $0.425 per unit per quarter, in connection with our initial public offering.

Since its inception in 1994, Wexford has been an active and successful investor in a variety of sectors, including energy and natural resource businesses. Wexford has made numerous investments in various aspects of the energy sector, and at present holds substantial interests in companies with oil, gas and coalbed methane assets in major producing areas of the United States and abroad. Through these and other investments, Wexford has demonstrated a proven and profitable track record in identifying, acquiring and developing oil and natural gas assets in a broad number of operating basins in North America and abroad.

Many of Wexford's investments involve controlling interests in private companies, both in the energy sector and in other areas, and Wexford has a track record of successfully growing such private companies. Wexford's strategy for such companies, including Rhino Energy LLC, involves recruiting strong management teams to focus on, among other things, internal growth and acquisitions of assets. Wexford also provides substantial ongoing assistance to the companies it controls. Such assistance includes market analysis and analysis of industry trends, sales and hedging assistance, assistance in acquisitions, financings and other transactions, legal and corporate secretary support, accounting support and investor relations. In addition, Wexford often assists management teams in adding capabilities to expand into complementary business lines. This approach has been successfully employed by Wexford in its energy companies.

In addition, Wexford has significant involvement in the natural resource transportation sector, including existing or previous investments in oil tankers and coal and iron ore bulk carriers. Wexford also has significant expertise and experience in distressed investments. Its first involvement with the coal industry was through the purchase of distressed securities of certain coal companies.

With its diverse background in the energy and related sectors, in managing private companies and in financing and acquisition transactions, Wexford has provided us with substantial assistance. In the future, we would expect that Wexford will continue to be involved in providing such assistance as well as strategic guidance concerning the growth of us and our mining operations and making other major decisions concerning our business.

Our general partner and its affiliates, including Wexford, will not receive any management fee or other compensation in connection with its management of our business but will be entitled to be reimbursed for all direct and indirect expenses incurred on our behalf. Wexford will charge on a fully allocated cost basis for services provided to us, other than legal support which will be on an hourly basis. This fully allocated cost basis is based on the percentage of time spent by Wexford personnel on our matters and includes the compensation paid by Wexford to such persons and their allocated overhead. The allocation of compensation expense for those executive officers of our general partner who are employees of Wexford will be determined based on a good faith estimate of the value of each such executive officer's services performed on our business and affairs, subject to the approval of the audit committee of our general partner. The fully allocated basis charged by Wexford does not include a profit component. Our general partner will be entitled to distributions on its general partner interest and, if specified requirements are met, on its incentive distribution rights. Please read "Certain Relationships and Related Party Transactions."

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Coal Operations

Mining Operations

As of December 31, 2007, we operated two mining complexes located in Central Appalachia (Tug River and Rob Fork), two mining complexes located in Northern Appalachia (Hopedale and Sands Hill) and one mine located in Colorado. We acquired the Deane mining complex in February 2008. We define a mining complex as a central location for processing raw coal and loading coal into railroad cars or trucks for shipment to customers. These mining facilities include five preparation plants and/or loadouts, each of which receive, blend, process and ship coal that is produced from one or more of our 20 active surface and underground mines. All of our preparation plants are modern plants that have both coarse and fine coal cleaning circuits.

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

Central Appalachia. We operate three mining complexes located in Central Appalachia consisting of ten active underground mines, five of which are company-operated with the remaining five being contractor-operated. In addition, we operate five company surface mines, and we have one contractor-operated surface mine. For the year ended December 31, 2007, these mines produced an aggregate of approximately 5.3 million tons of steam coal and approximately 0.3 million tons of metallurgical coal. As of October 31, 2007, we controlled approximately 70.8 million tons of proven and probable coal reserves and approximately 24.6 million tons of non-reserve coal deposits in Central Appalachia. The Deane mining complex added approximately 7.2 million tons of proven and probable coal reserves and approximately 0.2 million tons of non-reserve coal deposits as of the acquisition date, February 8, 2008. The Bolt field added approximately 15.3 million tons of proven and probable coal reserves and approximately 24.6 million tons of non-reserve coal deposits as of the lease date, February 15, 2008.

The following table provides summary information regarding our mining complexes in Central Appalachia as of March 31, 2008.

						Tons Produced for the Year Ended December 31, 2007
			Number and Type of Active Mines(1)
Mining Complex (Location)	Preparation Plants and Loadouts	Transportation to Customers	Company-Operated Mines	Contractor-Operated Mines	Total Mines
						(in millions)
Tug River (KY, WV)	Jamboree(2)	NS, Truck, Barge	2S	1S	3S	2.3
Rob Fork (KY)	Rob Fork	CSX, Truck, Barge	4U; 3S	2U	6U; 3S	3.3
Deane (KY)	Rapid Load	CSX, Truck	1U	3U	4U	—

Total			5U; 5S	5U; 1S	10U; 6S	5.6

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

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Tug River Mining Complex. The following map outlines the mines and loadout facility that comprise our Tug River mining complex as of March 31, 2008:

[MAP TO COME]

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

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

Rob Fork Mining Complex. The following map outlines the mines, preparation plant and loadout facility that comprise our Rob Fork mining complex as of March 31, 2008:

[MAP TO COME]

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

Our Rob Fork mining complex produces coal from three company-operated surface mines, two contractor-operated underground mines and four company-operated underground mines. In 2007, in an effort to enhance production at our Rob Fork mining complex, we completed development of a new underground metallurgical coal mine. Our investment of approximately $30.0 million included a conveyor belt to transfer coal from the mine portal directly to the preparation plant as well as an extensive entry system to access the main reserve body. Today, the mine accounts for approximately 650,000 tons per year of metallurgical coal production with an expected reserve life of 12.6 years. The Rob Fork mining complex located on the CSX Rail consists of a modern 700 tons-per-hour preparation plant utilizing heavy media circuitry and is capable of cleaning coarse and fine coal size fractions combined with a unit train loadout with batch weighing equipment capable of loading in excess of 10,000 tons into railcars in less than four hours. The mining complex has significant blending capabilities allowing the blending of raw coals with washed coals to meet a wide variety of customers' needs.

Deane Mining Complex. The following map outlines the mines, preparation plant and loadout facility that comprise our Deane mining complex as of March 31, 2008:

[MAP TO COME]

Our Deane mining complex is located in eastern Kentucky and, as of the acquisition date, included approximately 7.2 million tons of proven and probable coal reserves and approximately 0.2 million tons of non-reserve coal deposits. We expect to produce approximately 0.6 million tons of coal from the Deane mining complex for the year ending December 31, 2008 and 1.0 million tons of coal for the year ending December 31, 2009.

Our Deane mining complex produces steam coal from one company-operated underground mine and three contractor-operated underground mines. The infrastructure consists of a 950 tons-per-hour preparation plant and a loadout facility, utilizing heavy media circuitry and is capable of cleaning coarse and fine coal size fractions combined with a unit train loadout with batch weighing equipment capable of loading in excess of 10,000 tons into railcars in less than four hours. The facility has

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significant blending capabilities allowing the blending of raw coals with washed coals to meet a wide variety of customers' needs.

Northern Appalachia. We operate two mining complexes located in Northern Appalachia consisting of one company-operated underground mine and two company-operated surface mines. In the year ended December 31, 2007, these mines produced an aggregate of approximately 1.3 million tons of steam coal. As of October 31, 2007, we controlled approximately 47.6 million tons of proven and probable coal reserves and approximately 50.3 million tons of non-reserve coal deposits in Northern Appalachia. The Sands Hill mining complex added approximately 11.4 million tons of proven and probable coal reserves and approximately 3.9 million tons of non-reserve coal deposits as of the acquisition date, December 14, 2007. We also control non-reserve coal deposits of approximately (1) 10.6 million tons in the Leesville field and (2) 16.5 million tons in the Springdale field.

The following table provides summary information regarding our mining complexes in Northern Appalachia as of March 31, 2008:

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

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

Hopedale Mining Complex. The Hopedale mine is an underground mine located in Hopedale, Ohio about five miles northeast of Cadiz, Ohio. As of October 31, 2007, the Hopedale mining complex included approximately 17.1 millions of proven and probable coal reserves and approximately 23.2 million tons of non-reserve coal deposits. Coal produced from the Hopedale mine is first cleaned at our Nelms preparation plant located on the OHC Rail in Cadiz, Ohio and then shipped by train or truck to the customer. The infrastructure includes a full-service loadout facility. This underground mining operation produced approximately 1.3 million tons of steam coal for the year ended December 31, 2007.

The following map outlines the mine, preparation plant and loadout facility that comprise our Hopedale mining complex as of March 31, 2008:

[MAP TO COME]

Sands Hill Mining Complex. In December 2007, we acquired the assets of Sands Hill Coal Company which included two surface mines located near Hamden, Ohio. These two mines are expected to produce approximately 0.8 million tons of steam coal and approximately 0.7 million tons of high quality aggregate limestone for the year ending December 31, 2008 and approximately 1.0 million tons of steam coal and approximately 1.2 million tons of high quality aggregate limestone for the year ending December 31, 2009. As of December 14, 2007, these two mines included approximately 11.4 millions of proven and probable coal reserves, approximately 3.9 million tons of non-reserve coal deposits, approximately 21.6 million tons of proven and probable limestone reserves and approximately 3.7 million tons of non-reserve limestone deposits. The acquisition also included a 260 tons-per-hour preparation plant.

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The following map outlines the mines and preparation plant that comprise our Sands Hill mining complex as of March 31, 2008:

[MAP TO COME]

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Colorado. We operate an underground mine in Colorado in the Western Bituminous region under a contract mining agreement with CAM-Colorado LLC. In connection with the closing of this offering, Rhino Energy LLC will distribute its ownership interests in CAM-Colorado LLC to NR Energy LLC. The mine is the McClane Canyon mine near Loma, Colorado and is located on property leased by CAM-Colorado LLC from the BLM. We have the right pursuant to the contract mining agreement to produce a total maximum tonnage of 1.5 million tons of coal, until the contract terminates on March 31, 2011. We currently produce approximately 0.3 million tons per year and sell the coal produced from the McClane Canyon mine to Xcel's Cameo power plant, located east of Grand Junction, Colorado. The current contract with Xcel will expire December 31, 2008. We plan to renew this contract, however Xcel has announced that it plans to close its Cameo power plant. Under the contract mining agreement we pay all costs associated with the mining operation, including royalties due to the BLM. We retain the purchase price received for the sale of the coal and pay to CAM-Colorado LLC a per ton amount of $0.50. Please read "Certain Relationships and Related Party Transactions—Colorado Mining Agreement."

Trucking

In February 2007, we initiated the first major step of our vertical integration strategy, with the introduction of Rhino Trucking. The primary goal of integrating the trucking operations was to provide our Kentucky coal operations with dependable, safe coal hauling to our preparation plants and loadout facilities and reduce third-party trucking costs. From an initial fleet of two trucks, our fleet now includes 34 trucks and hauls approximately 85% of our Kentucky coal production that must be transported by truck. In addition to the mining operation, the Sands Hill acquisition also provided an opportunity to expand the reach of our trucking operations into the southeastern Ohio region to transport coal to our customers where rail is not available.

Reclamation

While we are committed to minimizing our environmental impact during the mining process, there is always some degree of environmental impact when the mining activity is completed. To minimize the long-term environmental impact of our mining activities, we plan and monitor each phase of our mining projects as well as the post-mining reclamation efforts. As of December 31, 2007, we had approximately $15.0 million in letters of credit pledged to secure the performance of our reclamation obligations. In addition to providing surety bonds, we have also made a significant investment to complete the required reclamation activities in a timely and professional manner to cause the bond to be released and to eliminate our impact. In August 2007, we began the integration of mine related construction, site and roadway maintenance and post-mining reclamation. Since then, we have been able to efficiently supply the majority of these services internally that were previously outsourced.

Coal Reserves and Non-Reserve Coal Deposits

Our coal reserve and non-reserve coal deposit estimates are based on geological data assembled and analyzed by our staff of geologists and engineers and economic data such as cost of production, projected sale price as well as other data concerning permitability and advances in mining technology. These estimates are periodically updated to reflect past coal production, new drilling information and other geologic or mining data. Acquisitions or sales of coal properties will also change theses estimates. Changes in mining methods may increase or decrease the recovery basis for a coal seam as will plant processing efficiency tests. We maintain reserve and non-reserve coal deposit information in secure computerized databases, as well as in hard copy. The ability to update and/or modify the estimates of our coal reserves and non-reserve coal deposits is restricted to a few individuals and the modifications are documented.

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Periodically, we retain outside experts to independently verify our coal reserves and our non-reserve coal deposits. The most recent review was completed as of October 31, 2007 (except for information regarding the Deane mining complex, which is as of the acquisition date, February 8, 2008; the Bolt field, which is as of the lease date, February 15, 2008; and the Sands Hill mining complex, which is as of the acquisition date, December 14, 2007) and covered all of our reserves and non-reserve coal deposits we controlled as of such date. The results verified our estimates, with minor adjustments and included an in-depth review of our procedures and controls. Our coal reserves of approximately 256.2 million tons and our non-reserve coal deposits of approximately 126.5 million tons as of October 31, 2007 (except for information regarding the Deane mining complex, which is as of the acquisition date, February 8, 2008; the Bolt field, which is as of the lease date, February 15, 2008; and the Sands Hill mining complex, which is as of the acquisition date, December 14, 2007) were confirmed by Marshall Miller.

Coal Reserves

"Reserves" are defined by the SEC Industry Guide 7 as that part of a mineral deposit that could be economically and legally extracted or produced at the time of the reserve determination. Industry Guide 7 divides reserves between "proven (measured) reserves" and "probable (indicated) reserves" which are defined as follows:

•: "Proven (measured) reserves." Reserves for which (1) quantity is computed from dimensions revealed in outcrops, trenches, workings or drill holes; grade and/or quality are computed from the results of detailed sampling and (2) the sites for inspection, sampling and measurement are spaced so closely and the geologic character is so well defined that size, shape, depth and mineral content of reserves are well-established.
•: "Probable (indicated) reserves." Reserves for which quantity and grade and/or quality are computed from information similar to that used for proven (measured) reserves, but the sites for inspection, sampling, and measurement are farther apart or are otherwise less adequately spaced. The degree of assurance, although lower than that for proven (measured) reserves, is high enough to assume continuity between points of observation.

As of October 31, 2007 (except for information regarding the Deane mining complex, which is as of the acquisition date, February 8, 2008; the Bolt field, which is as of the lease date, February 15, 2008; and the Sands Hill mining complex, which is as of the acquisition date, December 14, 2007), we owned 21.0% of our coal reserves and leased 79.0% of our reserves from various third-party landowners. The majority of our leases has an initial term denominated in years but also provide for the term of the lease to continue until exhaustion of the "mineable and merchantable" coal in the lease area so long as the terms of the lease are complied with. Some of our leases have terms denominated in years rather than mine-to-exhaustion provisions, but in all such cases, we believe that the term of years will allow the recoverable reserve to be fully extracted in accordance with our projected mine plan. Consistent with industry practice, we conduct only limited investigations of title to our coal properties prior to leasing. Title to lands and reserves of the lessors or grantors and the boundaries of our leased priorities are not completely verified until we prepare to mine those reserves.

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

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

		Total Central Appalachia	93.3	90.2		3.1		14.0		79.3		81.0		12.3

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

		Total Northern Appalachia	59.0	23.1		35.9		39.7		19.3		59.0		—

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

Total			256.2	114.8		141.4		53.7		202.5		243.9		12.3

Percentage of total				44.8	%	55.2	%	21.0	%	79.0	%	95.2	%	4.8	%

(1): The proven and probable coal reserves are reported as recoverable coal reserves, which is the portion that could be economically and legally extracted or produced at the time of the reserve determination, taking into account mining recovery and preparation plant yield. Excludes information regarding approximately 19.3 million tons of proven and probable coal reserves in Colorado to be controlled by Wexford after this offering.
(2): Assigned reserves mean coal reserves that have been committed by us to operating mine shafts, mining equipment and plant facilities and so can be mined without a significant capital expenditure for mine development. Unassigned reserves represent coal reserves that have not been committed and that would require new mineshafts, mining equipment or plant facilities before operations could begin in the property. The primary reason for this distinction is to inform investors which coal reserves will require substantial capital expenditures before production can begin.
(3): For purposes of this table, we have defined metallurgical coal reserves as reserves located in those seams that historically have been of sufficient quality and characteristics to be able to be used in the steel making process. Some of the reserves in the metallurgical category can also be used as steam coal.
(4): Information regarding the Deane mining complex is as of the acquisition date, February 8, 2008; the Bolt field is as of the lease date, February 15, 2008; and the Sands Hill mining complex is as of the acquisition date, December 14, 2007.

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

			As Received Basis(1)(2)						Proven and Probable Coal Reserves(2)
										Sulfur Content
Region					% Sulfur			SO2/mm Btu		Sulfur Content
Region			% Ash		% Sulfur		Btu/lb.	SO2/mm Btu	Total	<1%		1-1.5%		>1.5%		Unknown
										(in million tons)
Central Appalachia
	Tug River Complex (KY, WV)		10.77	%	1.23	%	12,808	1.96	36.3	22.0		8.4		5.6		0.3
	Rob Fork Complex (KY)		6.12	%	1.08	%	12,832	2.21	34.5	21.8		2.9		7.4		2.4
	Deane Complex (KY)(3)		5.99	%	1.55	%	13.196	2.35	7.2	—		—		7.2		—
	Bolt Field (WV)(3)		3.87	%	0.57	%	14,094	0.82	15.3	15.3		—		—		—

		Total Central Appalachia	7.55	%	1.09	%	13,507	1.90	93.3	59.1		11.3		20.2		2.7

Northern Appalachia
	Hopedale Complex (OH)		6.64	%	2.18	%	13,026	3.35	17.1	—		—		17.1		—
	Sands Hill Complex (OH)(3)		11.76	%	3.59	%	11,830	6.03	11.4	—		—		11.4		—
	Leesville Field (OH)		6.21	%	2.21	%	13,152	3.36	16.7	—		—		16.7		—
	Springdale Field (PA)		6.63	%	1.72	%	13,443	2.55	13.8	—		—		13.8		—

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

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

Total			7.92	%	2.47	%	12,630	4.08	256.2	60.6		11.3		181.6		2.7

Percentage of total										23.7	%	4.4	%	70.9	%	1.0	%

(1): As received represents an analysis of a sample as received at a laboratory.
(2): Excludes information regarding approximately 19.3 million tons of proven and probable coal reserves in Colorado to be controlled by Wexford after this offering.
(3): Information regarding the Deane mining complex is as of the acquisition date, February 8, 2008; the Bolt field is as of the lease date, February 15, 2008; and the Sands Hill mining complex is as of the acquisition date, December 14, 2007.

Non-Reserve Coal Deposits

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

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

	Non-Reserve Coal Deposits
		Total Tons
Region	Total Tons	Total Tons
Region	Total Tons	Owned		Leased
	(in million tons)
Central Appalachia(1)	49.4	7.4		42.0
Northern Appalachia(2)	54.2	40.7		22.9
Other(3)	22.9	—		13.5

Total	126.5	48.1		78.4

Percentage of total		38.0	%	62.0	%

(1): Includes information regarding the Deane mining complex as of its acquisition date, February 8, 2008; and the Bolt field as of its lease date, February 15, 2008.
(2): Includes information regarding the Sands Hill mining complex as of its acquisition date, December 14, 2007.
(3): Includes information regarding the Taylorville field in the Illinois Basin and the McClane Canyon mine in Colorado.

Limestone

Our Sands Hill mining complex, which we acquired on December 14, 2007, includes approximately 21.6 million tons of proven and probable limestone reserves and approximately 3.7 million tons of non-reserve limestone deposits. Incidental to our coal mining process, we mine limestone and sell it as aggregate to various construction companies and road builders that are located in close proximity to the mining complex. We believe that our production of limestone will provide us with an additional source of revenues at a low incremental capital cost.

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

Other Natural Resource Assets

One of our business strategies is to expand our operations through strategic acquisitions, including the acquisition of stable, cash generating, non-coal natural resource assets. We believe that such assets would allow us to grow our cash available for distribution and enhance the stability of our cash flow by, for example, serving as a natural hedge to help mitigate our exposure to certain operating costs, such as diesel fuel.

Our sponsor, Wexford, has substantial experience in acquiring and operating natural resource assets and will assist us in identifying growth opportunities and additional management with the relevant expertise in acquiring such assets.

Customers

General

Our primary customers for our steam coal are electric utilities, a majority of which have investment grade credit ratings, and the metallurgical coal we produce is sold for end use by domestic and international steel producers. For the year ended December 31, 2007, 97% of our sales consisted

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of steam coal and the remaining 3% consisted of metallurgical coal. The majority of our electric utility customers purchase coal for terms of one to three years but we also supply coal on a spot basis for some of our customers. We derived 94% of our revenues from coal sales to our ten largest customers for the year ended December 31, 2007, with our top four customers accounting for 72% of our sales: Constellation Energy Commodities Group, Inc. (26%); American Electric Power Company, Inc. (18%); Progress Energy Inc. (16%); and Duke Energy Corp. (12%). At various times, we also actively participate in the OTC market. Incidental to our coal mining process, we mine limestone and sell it as aggregate to various construction companies and road builders that are located in close proximity to our Sands Hill mining complex.

Coal Supply Contracts

As of December 31, 2007, we had sales commitments of 13.6 million tons through 2010. Our sales commitments total 7.2 million tons, 3.6 million tons and 1.5 million tons for the years ending December 31, 2008, 2009 and 2010, respectively. These sales commitments represent 84%, 43% and 16% of our planned production of 8.6 million tons, 8.5 million tons and 9.3 million tons for the year ending December 31, 2008, 2009 and 2010, respectively. For the year ended December 31, 2007, approximately 74% of our aggregate sales were made under long-term contracts. We expect to continue selling a significant portion of our coal under long-term agreements.

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

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

Transportation

We ship coal to our customers by rail, truck or barge. The majority of our coal is transported to customers by either the CSX Rail or the NS Rail in eastern Kentucky and by the OHC Rail in Ohio. In addition, in southeastern Ohio, we use our own trucking operations to transport coal to our customers where rail is not available. Please read "—Coal Operations—Trucking." We use third-party trucking to transport coal to our customers in Colorado. In addition, coal from certain of our mines is located within economical trucking distance to the Big Sandy River and/or the Ohio River and can be transported by barge. It is customary for customers to pay the transportation costs to their location. For the year ended December 31, 2007, substantially all of our coal sales tonnage was shipped by rail.

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

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Suppliers

For the year ended December 31, 2007, we spent $107.9 million to obtain goods and services in support of our mining operations, excluding capital expenditures. Principal supplies used in our business include diesel fuel, explosives, maintenance and repair parts and services, roof control and support items, tires, conveyance structures, ventilation supplies and lubricants. We use third-party suppliers for a significant portion of our equipment rebuilds and repairs, drilling services and construction.

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

Competition

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

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

Regulation and Laws

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

•: employee health and safety;
•: mine permits and other licensing requirements;
•: air quality standards;
•: water quality standards;
•: storage of petroleum products and substances that are regarded as hazardous under applicable laws or which, if spilled, could reach waterways or wetlands;
•: plant and wildlife protection;
•: reclamation and restoration of mining properties after mining is completed;
•: the discharge of materials into the environment;
•: storage and handling of explosives;
•: wetlands protection;

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•: surface subsidence from underground mining;
•: the effects, if any, that mining has on groundwater quality and availability; and
•: legislatively mandated benefits for current and retired coal miners.

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

We are committed to conducting mining operations in compliance with applicable federal, state and local laws and regulations. However, because of extensive and comprehensive regulatory requirements, violations during mining operations do occur from time to time. None of the violations to date have had a material impact on our operations or financial condition.

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

Mining Permits and Approvals

Numerous governmental permits or approvals are required for mining operations. We may be required to prepare and present to federal, state or local authorities data pertaining to the effect or impact that any proposed production of coal may have upon the environment. All requirements imposed by any of these authorities may be costly and time consuming, and may delay or prevent commencement or continuation of mining operations in certain locations. Future legislation and administrative regulations may emphasize more heavily the protection of the environment and, as a consequence, our activities may be more closely regulated. Legislation and regulations, as well as future interpretations of existing laws and regulations, may require substantial increases in equipment and operating costs, or delays, interruptions or terminations of operations, the extent of any of which cannot be predicted.

Under some circumstances, substantial fines and penalties, including revocation of mining permits, may be imposed under the laws described above. Monetary sanctions and, in severe circumstances, criminal sanctions may be imposed for failure to comply with these laws. Regulations also provide that a mining permit can be refused or revoked if the permit applicant or permittee owns or controls, directly or indirectly through other entities, mining operations which have outstanding environmental violations. Although, like other coal companies, we have been cited for violations in the ordinary course of business, we have never had a permit suspended or revoked because of any violation, and the penalties assessed for these violations have not been material.

Before commencing mining on a particular property, we must obtain mining permits and approvals by state regulatory authorities of a reclamation plan for restoring, upon the completion of mining, the mined property to its approximate prior condition, productive use or other permitted condition. The permitting process for certain mining operations has extended over several years and we cannot assure you that we will not experience difficulty in obtaining mining permits in the future.

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Mine Health and Safety Laws

Stringent safety and health standards have been imposed by federal legislation since 1969 when the Coal Mine Health and Safety Act of 1969 was adopted. The Federal Mine Safety and Health Act of 1977, and regulations adopted pursuant thereto, significantly expanded the enforcement of health and safety standards and imposed comprehensive safety and health standards on numerous aspects of mining operations, including training of mine personnel, mining procedures, blasting, the equipment used in mining operations and other matters. The MSHA monitors compliance with these federal laws and regulations. Most of the states where we operate also have state programs for mine safety and health regulation and enforcement. Federal and state safety and health regulations affecting the coal industry are complex, rigorous and comprehensive, and have a significant effect on our operating costs. Our competitors in all of the areas in which we operate are subject to these same laws and regulations.

Our nonfatal days lost incidence rate is 34.2% below the industry average for the year ended December 31, 2007. Nonfatal days lost incidence rate is an industry standard used to describe occupational injuries that result in loss of one or more days from an employee's scheduled work. Our nonfatal days lost time incidence rate for all operations for the year ended December 31, 2007 was 2.18 as compared to the national average of 3.31 for the same period, as reported by the MSHA.

In addition, for the year ended December 31, 2007 our average MSHA violations per inspection day was 0.54, as compared to the national average of 1.26 violations per inspection day, 57.1% below the national average.

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

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

In 2006, MSHA promulgated new emergency rules on mine safety that address mine safety equipment, training, and emergency reporting requirements. The U.S. Congress enacted the Mine Improvement and New Emergency Response Act of 2006 (the "MINER Act"), which was signed into law on June 15, 2006. The MINER Act significantly amends the Federal Mine Safety and Health Act of 1977, requiring improvements in mine safety practices, increasing criminal penalties and establishing a maximum civil penalty for non-compliance, and expanding the scope of federal oversight, inspection and enforcement activities. MSHA published final rules implementing the MINER Act to revise both the emergency rules and MSHA's existing civil penalty assessment regulations, which resulted in an across-the-board increase in penalties from the existing regulations.

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

Black Lung Laws

Under federal black lung benefits laws, businesses that conduct current mining operations must make payments of black lung benefits to coal miners with black lung disease and to some survivors of a miner who dies from this disease. To help fund these benefits, a tax is levied on production of $1.10 per ton for underground-mined coal and $0.55 per ton for surface-mined coal, but not to exceed 4.4% of the applicable sales price, in order to compensate miners who are totally disabled due to black lung

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disease and some survivors of miners who died from this disease, and who were last employed as miners prior to 1970 or subsequently where no responsible coal mine operator has been identified for claims. In addition, some claims for which coal operators had previously been responsible will be obligations of the government trust funded by the tax. The Revenue Act of 1987 extended the termination date of this tax from January 1, 1996, to the earlier of January 1, 2014, or the date on which the government trust becomes solvent. For miners last employed as miners after 1969 and who are determined to have contracted black lung, we maintain insurance coverage sufficient to cover the cost of present and future claims or we participate in state programs that provide this coverage. We are also liable under state statutes for black lung and are covered through either insurance policies or state programs.

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

Workers' Compensation

We are required to compensate employees for work-related injuries. The states in which we operate consider changes in workers' compensation laws from time to time. We are insured under the Ohio State Workers Compensation Program for our operations in Ohio. Our remaining operations, including Central Appalachia and Colorado, are insured through Rockwood Casualty Insurance Company.

Surface Mining Control and Reclamation Act

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

SMCRA and similar state statutes require, among other things, that mined property be restored in accordance with specified standards and approved reclamation plans. The act requires that we restore the surface to approximate the original contours as soon as practicable upon the completion of surface mining operations. The mine operator must submit a bond or otherwise secure the performance of these reclamation obligations. Federal law and some states impose on mine operators the responsibility for replacing certain water supplies damaged by mining operations and repairing or compensating for damage to certain structures occurring on the surface as a result of mine subsidence, a consequence of long-wall mining and possibly other mining operations. In addition, the Abandoned Mine Lands Program, which is part of SMCRA, imposes a tax on all current mining operations, the proceeds of which are used to restore mines closed before 1977. The maximum tax is 31.5 cents per ton on surface-mined coal and 13.5 cents per ton on underground-mined coal. The Abandoned Mine Lands tax was set to expire on June 30, 2006, but the program was extended until September 30, 2021. We have accrued for the estimated costs of reclamation and mine closing, including the cost of treating mine water discharge when necessary. In addition, states from time to time have increased and may continue to increase their fees and taxes to fund reclamation of orphaned mine sites and abandoned mine drainage control on a statewide basis.

Federal and state laws require bonds to secure our obligations to reclaim lands used for mining and to satisfy other miscellaneous obligations. These bonds are typically renewable on a yearly basis. It has become increasingly difficult for mining companies to secure new surety bonds without the posting of partial collateral. In addition, surety bond costs have increased while the market terms of surety

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bonds have generally become less favorable. It is possible that surety bonds issuers may refuse to renew bonds or may demand additional collateral upon those renewals. Our failure to maintain, or inability to acquire, surety bonds that are required by state and federal laws would have a material adverse effect on our ability to produce coal, which could affect our profitability and cash flow.

Air Emissions

The Federal Clean Air Act ("CAA"), and similar state and local laws and regulations, which regulate emissions into the air, affect coal mining operations both directly and indirectly. The CAA directly impacts our coal mining and processing operations by imposing permitting requirements and, in some cases, requirements to install certain emissions control equipment, on sources that emit various hazardous and non-hazardous air pollutants. The CAA also indirectly affects coal mining operations by extensively regulating the air emissions of coal-fired electric power generating plants and other industrial consumers of coal. There have been a series of recent federal rulemakings that are focused on emissions from coal-fired electric generating facilities. Installation of additional emissions control technology and additional measures required under EPA laws and regulations will make it more costly to operate coal-fired power plants and possibly other facilities that consume coal and, depending on the requirements of individual state implementation plans, could make coal a less attractive fuel alternative in the planning and building of power plants in the future. Any reduction in coal's share of power generating capacity could have a material adverse effect on our business, financial condition and results of operations.

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

EPA has promulgated rules, referred to as the "NOx SIP Call," that require coal-fired power plants in 21 eastern states and Washington D.C. to make substantial reductions in nitrogen oxide emissions in an effort to reduce the impacts of ozone transport between states. Additionally, in March 2005, EPA issued the final Clean Air Interstate Rule ("CAIR"), which will permanently cap nitrogen oxide and sulfur dioxide emissions in 28 eastern states and Washington, D.C. beginning in 2009 and 2010, respectively. CAIR requires these states to achieve the required emission reductions by requiring power plants to either participate in an EPA-administered "cap-and-trade" program that caps emission in two phases, or by meeting an individual state emissions budget through measures established by the state. The stringency of the caps under CAIR may require many coal-fired sources to install additional pollution control equipment, such as wet scrubbers, to comply. This increased sulfur emission removal capability required by the rule could result in decreased demand for lower sulfur coal, potentially driving down prices for lower sulfur coal.

In March 2005, EPA finalized the Clean Air Mercury Rule ("CAMR"), which establishes a two-part nationwide cap on mercury emissions from coal-fired power plants beginning in 2010. The CAMR has been the subject of ongoing litigation, and on February 8, 2008, the D.C. Circuit Court of Appeals vacated the rule for further consideration by the U.S. EPA. While the future of the CAMR is uncertain, certain states have adopted or proposed mercury control regulations that are more stringent than the federal requirements, which could reduce the demand for coal in those states.

EPA has adopted new, more stringent national air quality standards for ozone and fine particulate matter. As a result, some states will be required to amend their existing state implementation plans to

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

In June 2005, EPA announced final amendments to its regional haze program originally developed in 1999 to improve visibility in national parks and wilderness areas. As part of the new rules, affected states must develop implementation plans by December 2007 that, among other things, identify facilities that will have to reduce emissions and comply with stricter emission limitations. This program may restrict construction of new coal-fired power plants where emissions are projected to reduce visibility in protected areas. In addition, this program may require certain existing coal-fired power plants to install emissions control equipment to reduce haze-causing emissions such as sulfur dioxide, nitrogen oxide, and particulate matter. Demand for our steam coal could be affected when these new standards are implemented by the applicable states.

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

Carbon Dioxide Emissions

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

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

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greenhouse gas emissions raised in New York State back to EPA for further regulatory consideration in light of the Supreme Court's holding in Massachusetts.

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

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

Clean Water Act

The Federal Clean Water Act ("CWA") and similar state and local laws and regulations affect coal mining operations by imposing restrictions on the discharge of pollutants, including dredged or fill material, into waters of the United States. The CWA establishes in-stream water quality and treatment standards for wastewater discharges through Section 402 National Pollutant Discharge Elimination System ("NPDES") permits. Regular monitoring, as well as compliance with reporting requirements and performance standards, are preconditions for the issuance and renewal of Section 402 NPDES permits. Individual or general permits under Section 404 of the CWA are required to discharge dredged or fill materials into jurisdictional waters of the United States. Surface coal mining operators obtain such permits to authorize activities such as the creation of slurry ponds, stream impoundments, and valley fills.

Recent federal district court decisions in West Virginia, and related litigation filed in federal district court in Kentucky, have created uncertainty regarding the future ability to obtain certain general permits authorizing the construction of valley fills for the disposal of overburden from mining operations. The U.S. Army Corps of Engineers ("Corps") is authorized to issue general "nationwide" permits for specific categories of activities that are similar in nature and that are determined to have minimal adverse environmental effects. Nationwide Permit 21 authorizes the disposal of dredged or fill material from surface coal mining activities into the waters of the United States. A July 2004 decision by the U.S. District Court for the Southern District of West Virginia in Ohio Valley Environmental Coalition v. Bulen enjoined the Huntington District of the Corps from issuing further permits pursuant to Nationwide Permit 21. While this decision was vacated by the U.S. Court of Appeals for the Fourth Circuit in November 2005, it has been remanded to the District Court for the Southern District of West Virginia for further proceedings. Moreover, a similar lawsuit has been filed in the U.S. District Court for the Eastern District of Kentucky that seeks to enjoin the issuance of permits pursuant to Nationwide Permit 21 by the Louisville District of the Corps. We currently utilize Nationwide Permit 21 authorizations, and these court cases have created uncertainty regarding our ability to utilize this form of permit in the future for the disposal of dredged or fill material.

Individual CWA Section 404 permits for valley fill surface mining activities are also subject to legal uncertainties. On June 15, 2006, the U.S. Supreme Court decided the combined cases of Rapanos v.

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

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

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

Under the CWA, states also must conduct an antidegradation review before approving permits for the discharge of pollutants to waters that have been designated as high quality. A state's antidegradation regulations must prohibit the diminution of water quality in these streams absent an analysis of alternatives to the discharge and a demonstration of the socio-economic necessity for the discharge. Several environmental groups and individuals have challenged West Virginia's antidegradation policy. In general, waters discharged from coal mines to high quality streams in West Virginia will be required to meet or exceed new "high quality" standards. This could cause increases in the costs, time and difficulty associated with obtaining and complying with NPDES permits in West Virginia, and could adversely affect our coal production. Several other environmental groups have also challenged the EPA's approval of Kentucky's antidegradation policy, including its alternative

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antidegradation implementation methodology for permits associated with coal mining discharges, which recognizes that those discharges are subject to comparable regulation under SMCRA and Section 404 of the CWA. On March 31, 2006, the U.S. District Court for the Western District of Kentucky granted summary judgment in favor of the EPA and various intervening defendants, upholding the EPA's approval of Kentucky's antidegradation policy. The plaintiffs subsequently appealed the district court's decision to the U.S. Court of Appeals for the Sixth Circuit. An unfavorable decision on the merits by the Sixth Circuit could result in the elimination of the alternative implementation methodology for coal mining discharges or other provisions of Kentucky's antidegradation rules. Such an outcome could mean that our operations in Kentucky would be required to comply with more complex and costly antidegradation procedures and cause increases in the costs, time and difficulty associated with obtaining and complying with NPDES permits in Kentucky, and thereby adversely affect our coal production.

Hazardous Substances and Wastes

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

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

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

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

Endangered Species Act

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

Use of Explosives

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

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

Office Facilities

We lease office space in Lexington, Kentucky for our executives and administrative support staff. We lease our executive office space at 3120 Wall Street, Lexington, Kentucky, which lease expires June 2009, subject to us having four consecutive two-year renewal options. In addition, we lease a building primarily for our administrative support staff at 265 Hambley Boulevard, Pikeville, Kentucky, which lease expires June 30, 2010, subject to us having two consecutive five-year renewal options.

Employees

To carry out our operations, our subsidiaries employed over 875 full-time employees as of December 31, 2007. None of the employees are subject to collective bargaining agreements. We believe that we have good relations with these employees and since our inception we have had no history of work stoppages or union organizing campaigns. Certain of the employees will be providing services to entities owned by Wexford Funds pursuant to a shared services agreement that we will enter into upon the consummation of this offering. Please read "Certain Relationships and Related Party Transactions—Shared Services Agreement."

Legal Proceedings

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

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MANAGEMENT

Management of Rhino Resource Partners, L.P.

We are managed and operated by the directors and executive officers of our general partner, Rhino GP LLC. Our general partner is not elected by our unitholders and will not be subject to re-election on a regular basis in the future. The Wexford Principals will own 100% of the ownership interests in our general partner. Rhino GP LLC will have a board of directors, and unitholders will not be entitled to elect the directors or directly or indirectly participate in our management or operation. Certain executive officers and directors of our general partner are Wexford Principals. Our general partner owes certain fiduciary duties to our unitholders as well as a fiduciary duty to its owners. Our general partner will be liable, as general partner, for all of our debts (to the extent not paid from our assets), except for indebtedness or other obligations that are made specifically nonrecourse to it. Whenever possible, our general partner intends to incur indebtedness that is nonrecourse.

Our conflicts committee, comprised solely of independent directors, will determine if the resolution of the conflict of interest is fair and reasonable to us. The members of the conflicts committee may not be executive officers or employees of our general partner or directors, executive officers or employees of its affiliates and must meet the independence and experience standards established by the NASDAQ Global Select Market and the Securities Exchange Act of 1934. Any matters approved by the conflicts committee will be conclusively deemed to be fair and reasonable to us, approved by all of our partners, and not a breach by our general partner of any duties it may owe us or our unitholders. In addition, we will have an audit committee and a compensation committee.

Even though most companies listed on the NASDAQ Global Select Market are required to have a majority of independent directors serving on the board of directors of the listed company, the NASDAQ Global Select Market does not require a listed limited partnership like us to have a majority of independent directors on the board of directors of its general partner.

In compliance with the rules of the NASDAQ Global Select Market, the members of the board of directors named below will appoint an additional independent member within 90 days of the listing and one additional independent member within twelve months of listing. Thereafter, our general partner is generally required to have at least three independent directors serving on its board at all times. John McCarty, along with two other independent board members to be appointed, will serve as the initial members of the conflicts, audit and compensation committees.

Directors and Executive Officers

The following table shows information for the directors and executive officers of our general partner.

Name	Age	Position
Mark D. Zand	54	Chairman of the Board
Nicholas R. Glancy	53	President, Chief Executive Officer and Director
Richard A. Boone	54	Senior Vice President and Chief Financial Officer
David G. Zatezalo	52	Chief Operating Officer
Christopher N. Moravec	52	Senior Vice President of Business Development
Thomas Hanley	53	Senior Vice President
Jay L. Maymudes	47	Vice President—Finance and Administration, Secretary and Director
Arthur H. Amron	51	Vice President, Assistant Secretary and Director
Kenneth A. Rubin	53	Director
John P. McCarty	62	Director Nominee

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Mark D. Zand was elected Chairman of the Board of Directors of our general partner in March 2006. He is a Principal of Wexford. Mr. Zand joined Wexford in 1996 and became a Principal in 2001. Mr. Zand is involved in fixed income and distressed securities research and trading, and in public and private equity investing. Mr. Zand has been actively involved with Wexford's coal investments since their inception.

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

Richard A. Boone was elected Senior Vice President and Chief Financial Officer of our general partner in April 2008. He has been employed as Senior Vice President and Chief Financial Officer of Rhino Energy LLC since February 2005. Prior to joining Rhino Energy LLC, he served as Vice President and Corporate Controller of PinnOak Resources, LLC, a coal producer serving the steel making industry, since 2003. Prior to joining PinnOak Resources, LLC, he served as Vice President, Treasurer and Corporate Controller of Horizon Natural Resources Company, a producer of steam and metallurgical coal, since 1998.

David G. Zatezalo was elected Chief Operating Officer of our general partner in April 2008. He has been employed with Rhino Energy LLC as Chief Operating Officer since March 2007, in which role he is responsible for the operations of several subsidiaries of Rhino Energy LLC. Prior to joining Rhino Energy LLC in April 2004, Mr. Zatezalo served as President of AEP's various Appalachian Mining Operations and as General Manager of Windsor Coal Company. From 1995 to 1998 he served as General Manager of the Cliff Collieries and Manager of Underground Development in the Bowen Basin of Queensland for BHP Australia Coal. Mr. Zatezalo is a professional engineer registered in West Virginia and Ohio. Additionally, Mr. Zatezalo serves as Chairman of the Ohio Coal Association.

Christopher N. Moravec was elected Senior Vice President of Business Development of our general partner in April 2008. He has been employed as Senior Vice President of Business Development of Rhino Energy LLC since March 2006. Prior to joining Rhino Energy LLC, he was employed by PNC Bank for more than 22 years, most recently serving as Senior Vice President and Managing Director. In this capacity, he directly managed a commercial loan portfolio and directed the banks efforts in serving as an intermediary on behalf of coal industry clients to arrange syndicated financings, access private and public debt securities, and act as an agent is various merger and acquisition transactions.

Thomas Hanley was elected Senior Vice President of our general partner in April 2008. He has been employed with Rhino Energy LLC since September 2007 as its Senior Vice President of Administration. Prior to joining Rhino Energy LLC, Mr. Hanley was a vice president with Wexford Capital LLC where his main areas of focus were in evaluation, planning and optimization within the transportation and operations sector since September 2002.

Jay L. Maymudes was elected Vice President—Finance and Administration, Secretary, Treasurer and director of our general partner in April 2008. He is a Principal of Wexford. Mr. Maymudes joined Wexford in 1994 and became a Principal in 1997 and serves as Wexford's Chief Financial Officer. Mr. Maymudes is responsible for the financial, tax and reporting requirements of Wexford and all of its private investment partnerships and its trading activities. Mr. Maymudes is a Certified Public Accountant.

Arthur H. Amron was elected Vice President, Assistant Secretary and director of our general partner in March 2006. He is the General Counsel and a Principal of Wexford. Mr. Amron joined Wexford as General Counsel in 1994 and became a Principal in 1999. Mr. Amron is responsible for

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legal and securities compliance and actively participates in various private equity transactions, particularly in the bankruptcy and restructuring areas.

Kenneth A. Rubin was elected director of our general partner in March 2006. He is a Principal of Wexford. Mr. Rubin joined Wexford in 1996 and became a Principal in 2001. Mr. Rubin focuses on both private and public equity investing and also has responsibility for select tax, corporate and litigation legal matters.

John P. McCarty will serve as a director of our general partner upon the consummation of this offering and will serve as a member of the conflicts committee, the audit committee and the compensation committee of the board of directors of our general partner. In August 1989, Mr. McCarty founded Lexington Capital Advisors, Inc., a financial consulting and real estate development firm, for which he serves as President. From October 2004 to November 2006, Mr. McCarty served as a Commissioner of New Business Development for the Commonwealth of Kentucky.

Payments to Our General Partner and Wexford

Our general partner and its affiliates will not receive any management fee or other compensation in connection with its management of our partnership but will be reimbursed for expenses incurred on our behalf. These expenses include the costs of executive officer and director compensation and benefits properly allocable to us, and all other expenses necessary or appropriate to the conduct of our business and allocable to us. Our partnership agreement provides that our general partner will determine the expenses that are allocable to us.

Wexford will charge on a fully allocated cost basis for services provided to us, other than legal support which will be on an hourly basis. This fully allocated cost basis is based on the percentage of time spent by Wexford personnel on our matters and includes the compensation paid by Wexford to such persons and their allocated overhead. The allocation of compensation expense for those executive officers of our general partner who are employees of Wexford will be determined based on a good faith estimate of the value of each such executive officer's services performed on our business and affairs, subject to the approval of the audit committee of our general partner. The fully allocated basis charged by Wexford does not include a profit component.

Our general partner will maintain its 2% general partner interest in us. We will also issue to our general partner the incentive distribution rights, which entitle the holder to increasing percentages, up to a maximum of 10%, of the cash we distribute in excess of $0.425 per unit per quarter, in connection with our initial public offering. Our general partner will be entitled to distributions on its general partner interest and, if specified requirements are met, on its incentive distribution rights. Please read "Certain Relationships and Related Party Transactions."

Executive Compensation

All of our executive officers will be employed by our general partner or Wexford. Compensation for certain of the executive officers of our general partner will be determined pursuant to employment agreements between such executive officer and our general partner. Please read "—Employment Agreements." Compensation for those executive officers of our general partner who are employees of Wexford will be determined based on a good faith estimate of the value of the services performed on our business and affairs, subject to the approval of the audit committee of our general partner.

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

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

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

Upon the consummation of this offering, the following named executive officers will each receive a grant of phantom units under the Rhino Resource Partners, L.P. Long-Term Incentive Plan in the amount set out beside each name, based on the closing price of our common units on the date of our initial public offering: Mr. Glancy ($1,350,000), Mr. Boone ($500,000), Mr. Zatezalo ($800,000), Mr. Moravec ($300,000) and Mr. Hanley ($500,000). The phantom units will vest in one-third increments over a three-year period, subject to earlier vesting on a change of control or upon a termination without cause or due to death or disability. Each grantee will receive one common unit (or cash equivalent) upon vesting of the phantom unit. In addition, the phantom units will have distribution equivalent rights for each fiscal quarter. The grant will be made within three business days of the closing of the initial public offering. Mr. Glancy will also be granted bonus units in the amount of $450,000, based on the closing price of our common units on the date of our initial public offering. The bonus units are not subject to forfeiture. Please read "—Long-Term Incentive Plan."

Compensation Discussion and Analysis

The compensation for the named executive officers for services rendered to us will be determined by the compensation committee of our general partner. Our "named executive officers" will include our Chief Executive Officer, our Chief Financial Officer and the three other most highly compensated executive officers. Our general partner seeks to improve our financial and operating performance and provide a desirable return on investment to holders of our common units, while maintaining financial strength and flexibility. The compensation committee of our general partner will seek to provide a total compensation package designed to drive performance and reward contributions in support of this business strategy and to attract, motivate and retain high quality talent with the skills and competencies required by us. As part of its review, the compensation committee will examine the compensation practices of our peer companies. Changes may occur from time to time in the composition of this peer group to reflect mergers, acquisitions, initial public offerings and similar events. The compensation committee will also review compensation data from the general coal industry as it believes that the competition for executive talent is broader than just the peer companies. In addition, the compensation committee may review and, in certain cases, participate in, various relevant compensation surveys and

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consult with compensation consultants with respect to determining compensation for the named executive officers.

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

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

Base Salary. Our general partner's compensation committee will establish base salaries for the named executive officers based on various factors including the amounts it considers necessary to attract and retain the highest quality executives, the responsibilities of the named executive officers and market data including publicly available market data for the peer companies listed above as reported in their filings with the SEC. The compensation committee will review the base salaries on an annual basis. As part of its review, the compensation committee may review the compensation of executives in similar positions with similar responsibility in the peer companies listed above and in companies in the coal industry with which we believe we generally compete for executives.

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

Discretionary Bonus Awards. Our general partner's compensation committee may also award discretionary bonus awards to the named executive officers. Our general partner intends to use discretionary bonus awards for achieving financial and operational goals and for achieving individual performance objectives. The named executive officer's discretionary bonus will be in the range of 0% to 40% of his annual salary.

Long-Term Incentive Plan Awards. Our general partner intends to adopt a long-term incentive plan for employees, consultants and directors of our general partner and its affiliates who perform services for us. Each of the named executive officers will be eligible to participate in this plan. The long-term incentive plan provides for the grant of unit awards, restricted units, phantom units, unit options, unit appreciation rights, distribution equivalent rights and substitute awards. For a more detailed description of this plan, please read "—Long-Term Incentive Plan."

In connection with our initial public offering, the following named executive officers will each receive a grant of phantom units with distribution rights under our Long-Term Incentive Plan in the amount set out beside each name, based on the closing price of our common units on the date of our initial public offering: Mr. Glancy ($1,350,000), Mr. Boone ($500,000), Mr. Zatezalo ($800,000), Mr. Moravec ($300,000) and Mr. Hanley ($500,000). The phantom units will vest in one-third increments over a three-year period, subject to earlier vesting on a change of control or upon a termination without cause or due to death or disability. Each grantee will receive one common unit (or cash equivalent) upon vesting of the phantom unit. In addition, the phantom units will have distribution equivalent rights for each fiscal quarter. The grant will be made within three business days of the initial

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public offering. Mr. Glancy will also be granted bonus units in the amount of $450,000, based on the closing price of our common units on the date of our initial public offering. The bonus units are not subject to forfeiture. Please read "—Long-Term Incentive Plan."

Other Benefits. The employment agreements to be entered into by each of the named executive officers with our general partner provide that the named executive officer is eligible to participate in our 401(k) plan.

Compensation Mix. Our general partner's compensation committee will determine the mix of compensation, both among short-term and long-term compensation and cash and non-cash compensation, to establish structures that it believes are appropriate for each of the named executive officers. We believe that the mix of base salary, discretionary bonus awards, awards under the long-term incentive plan and the other benefits that will be available to the named executive officers fit the overall compensation objectives of our general partner and us. We believe this mix of compensation provides competitive compensation opportunities to align and drive employee performance in support of our business strategies and to attract, motivate and retain high quality talent with the skills and competencies required by us.

Role of Executive Officers in Executive Compensation. Our general partner's compensation committee will determine the compensation of the named executive officers. We expect that our chief executive officer, Mr. Glancy, will provide periodic recommendations to the compensation committee regarding the compensation of other named executive officers.

Employment Agreements

Upon the consummation of this offering, Messrs. Glancy, Boone, Zatezalo, Moravec and Hanley will enter into employment agreements with our general partner. These agreements will have termination dates ranging from December 31, 2009 through May 31, 2011 and will provide for a base salary and annual bonus and, in some cases a bonus upon the consummation of this offering, as described above in "—Executive Compensation," and participation in certain benefit plans.

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

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

Compensation of Directors

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

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Long-Term Incentive Plan

The board of directors of our general partner will adopt the Rhino Resource Partners, L.P. Long-Term Incentive Plan for employees, consultants and directors of our general partner and affiliates who perform services for us. The long-term incentive plan will consist of six components: restricted units; phantom units; bonus units; unit options; unit appreciation rights and distribution equivalent rights. The long-term incentive plan will limit the number of units that may be delivered pursuant to awards to 10% of the outstanding units on the effective date of the initial public offering of the units. Units withheld to satisfy exercise prices or tax withholding obligations are available for delivery pursuant to other awards. The plan will be administered by the board of directors of our general partner or a committee thereof, which we refer to as the plan administrator.

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

Restricted Units

A restricted unit is a common unit that vests over a period of time and that during such time is subject to forfeiture. The plan administrator may determine to make grants of restricted units under the plan to our employees, consultants and directors and employees and consultants of our affiliates containing such terms as the plan administrator shall determine. The plan administrator will determine the period over which restricted units granted to participants will vest. The plan administrator, in its discretion, may base its determination upon the achievement of specified financial objectives. In addition, the restricted units will vest upon a change of control of our company, as defined in the plan, unless provided otherwise by the plan administrator. Distributions made on restricted units may be subjected to the same vesting provisions as the restricted unit. If a grantee's employment, consulting or membership on the board of directors terminates for any reason, the grantee's restricted units will be automatically forfeited unless, and to the extent, the plan administrator or the terms of the award agreement provide otherwise.

Common units to be delivered as restricted units may be common units acquired by our general partner in the open market, common units acquired from us or from any other person or any combination of the foregoing. If we issue new common units upon the grant of the restricted units, the total number of common units outstanding will increase.

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

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Phantom Units

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

Common units to be delivered upon the vesting of phantom units may be common units acquired by our general partner in the open market, common units acquired from us or from any other person or any combination of the foregoing. If we issue new common units upon vesting of the phantom units, the total number of common units outstanding will increase. The plan administrator, in its discretion, may grant tandem distribution equivalent rights with respect to phantom units that entitle the holder to receive cash equal to any cash distributions made on common units while the phantom units are outstanding.

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

Bonus Units

The long-term incentive plan will permit the grant of common units that are not subject to forfeiture by the participants. These bonus units may be in addition to, or in lieu of, cash compensation otherwise payable to the participant.

Unit Options

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

Upon exercise of a unit option, our general partner will acquire common units on the open market or directly from us or any other person or use any combination of the foregoing, in the plan administrator's discretion. If we issue new common units upon exercise of the unit options, the total number of common units outstanding will increase. The availability of unit options is intended to furnish additional compensation to plan participants and to align their economic interests with those of common unitholders.

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Unit Appreciation Rights

The long-term incentive plan will permit the grant of unit appreciation rights. A unit appreciation right is an award that, upon exercise, entitles the participant to receive the excess of the fair market value of a unit on the exercise date over the exercise price established for the unit appreciation right. Such excess will be paid in cash or common units. The plan administrator may determine to make grants of unit appreciation rights under the plan to our employees, consultants and directors and employees and consultants of our affiliates containing such terms as the plan administrator shall determine. Unit appreciation rights will have an exercise price that may not be less than the fair market value of the common units on the date of grant. In general, unit appreciation rights granted will become exercisable over a period determined by the plan administrator. In addition, the unit appreciation rights will become exercisable upon a change in control of our company, unless provided otherwise by the plan administrator. If a grantee's employment, consulting or membership on the board of directors terminates for any reason, the grantee's unvested unit appreciation rights will be automatically forfeited unless, and to the extent, the grant agreement or plan administrator provides otherwise.

Upon exercise of a unit appreciation right, our general partner will acquire common units on the open market or directly from us or any other person or use any combination of the foregoing, in the plan administrator's discretion. If we issue new common units upon exercise of the unit appreciation right, the total number of common units outstanding will increase. The availability of unit appreciation rights is intended to furnish additional compensation to plan participants and to align their economic interests with those of common unitholders.

Distribution Equivalent Rights

The plan administrator may, in its discretion, grant distribution equivalent rights ("DERs") with respect to phantom units. DERs entitle the participant to receive cash equal to the amount of any cash distributions made by us during the period the award is outstanding. Payment of a DER may be subject to the same vesting terms as the award to which it relates.

Substitute Awards

The plan administrator may grant awards to individuals who become eligible under the plan due to an acquisition, to replace substantially similar awards that may have been forfeited or terminated in the acquisition. With respect to substitute awards that are options or unit appreciation rights, their exercise price may be less than the fair market value of a unit on the price the substitute award is granted.

401(k) Plan

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

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SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT

The following table sets forth the beneficial ownership of units of Rhino Resource Partners, L.P. that will be issued upon the consummation of this offering and the related transactions and held

•: by beneficial owners of 5% or more of the units;
•: by each director, director nominee and executive officer of our general partner; and
•: by all directors and executive officers of our general partner as a group.

Name of Beneficial Owner	Common Units to be Beneficially Owned	Percentage of Common Units to be Beneficially Owned		Subordinated Units to be Beneficially Owned	Percentage of Subordinated Units to be Beneficially Owned		Percentage of Total Units to be Beneficially Owned
Charles E. Davidson(1)(2)	27,925,200	74.6	%	3,741,500	10.0	%	84.6	%
Joseph M. Jacobs(1)(2)	27,925,200	74.6	%	3,741,500	10.0	%	84.6	%
Wexford(1)(2)	27,925,200	74.6	%	3,741,500	10.0	%	84.6	%
Mark D. Zand(2)	—	—		—	—		—
Nicholas R. Glancy(3)	—	—		—	—		—
Richard A. Boone(3)	—	—		—	—		—
David G. Zatezalo(3)	—	—		—	—		—
Christopher N. Moravec(3)	—	—		—	—		—
Thomas Hanley(3)	—	—		—	—		—
Jay L. Maymudes(2)	—	—		—	—		—
Arthur H. Amron(2)	—	—		—	—		—
Kenneth A. Rubin(2)	—	—		—	—		—
John McCarty(4)	—	—		—	—		—
All directors and executive officers as a group (10 persons)	—	—		—	—		—

(1): Common and subordinated units shown as beneficially owned by Charles E. Davidson, Joseph M. Jacobs and Wexford reflect common and subordinated units owned of record by the following entities: Artis Investors LLC, Callidus Investors LLC, Taurus Investors LLC, Valentis Investors LLC, Solitair LLC, Wexford Spectrum Fund Liquidating LLC, Wexford Spectrum Fund, L.P., Wexford Offshore CAM Preferred Corp. and Wexford Offshore CAM Common Corp. Wexford serves as manager, investment advisor or subadvisor, as the case may be, for each of these entities and as such may be deemed to share beneficial ownership of any units beneficially owned by these entities, but disclaim such beneficial ownership. Messrs. Davidson and Jacobs, as the managing members of Wexford, may be deemed to share beneficial ownership of any units beneficially owned by the entities for which Wexford serves as manager, investment advisor or subadvisor, but disclaim such beneficial ownership.
(2): The address for this person or entity is 411 West Putnam Avenue, Greenwich, Connecticut 06830.
(3): The address for this person is 3120 Wall Street, Suite 310, Lexington, Kentucky 40513.
(4): The address for this person is 444 East Main Street, Suite 310, Lexington, Kentucky 40507.

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CERTAIN RELATIONSHIPS AND RELATED PARTY TRANSACTIONS

After this offering, Wexford Funds will own 27,925,200 common units and 3,741,500 subordinated units representing an 84.6% limited partner interest in us (or 82.9% limited partner interest in us, if the underwriters exercise their option to purchase additional common units in full) and the Wexford Principals will own and control our general partner which will maintain its 2% general partner interest in us and will be issued the incentive distribution rights.

Distributions and Payments to Our General Partner and Its Affiliates

The following table summarizes the distributions and payments to be made by us to our general partner and its affiliates in connection with the formation, ongoing operation and liquidation of Rhino Resource Partners, L.P. These distributions and payments were determined by and among affiliated entities and, consequently, are not the result of arm's-length negotiations.

*Formation Stage*
The consideration received by our general partner and its affiliates for the contribution of their interests	•	27,925,200 common units;
	•	3,741,500 subordinated units;
	•	2% general partner interest;
	•	the incentive distribution rights; and
	•	approximately $25.0 million.
*Operational Stage*
Distributions of available cash to our general partner and its affiliates	We will generally make cash distributions 98% to the unitholders, including affiliates of our general partner, as the holders of an aggregate of 27,925,200 common units and all of the subordinated units, and 2% to our general partner. In addition, if distributions exceed the minimum quarterly distribution and other higher target levels, our general partner will be entitled to increasing percentages of the distributions, up to 10% of the distributions above the highest target level.
	Assuming we have sufficient available cash to pay the full minimum quarterly distribution on all of our outstanding units for four quarters, our general partner and its affiliates would receive an annual distribution of approximately $1.1 million on the 2% general partner interest and approximately $55.0 million on their common units and subordinated units.

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Payments to our general partner and its affiliates		Our general partner will not receive a management fee or other compensation for its management of Rhino Resource Partners, L.P. Our general partner and its affiliates will be reimbursed for expenses incurred on our behalf. Our partnership agreement provides that our general partner will determine the amount of these expenses.
		Wexford will charge on a fully allocated cost basis for services provided to us, other than legal support which will be on an hourly basis. This fully allocated cost basis is based on the percentage of time spent by Wexford personnel on our matters and includes the compensation paid by Wexford to such persons and their allocated overhead. The allocation of compensation expense for those executive officers of our general partner who are employees of Wexford will be determined based on a good faith estimate of the value of each such executive officer's services performed on our business and affairs, subject to the approval of the audit committee of our general partner. The fully allocated basis charged by Wexford does not include a profit component.
Withdrawal or removal of our general partner		If our general partner withdraws or is removed, its general partner interest and its incentive distribution rights will either be sold to the new general partner for cash or converted into common units, in each case for an amount equal to the fair market value of those interests. Please read "The Partnership Agreement—Withdrawal or Removal of Our General Partner."
*Liquidation Stage*
Liquidation		Upon our liquidation, the partners, including our general partner, will be entitled to receive liquidating distributions according to their particular capital account balances.

Ownership Interests of Certain Executive Officers and Directors of Our General Partner

Upon the closing of this offering, the Wexford Principals, which include Mark D. Zand, Jay L. Maymudes, Arthur H. Amron and Kenneth A. Rubin, will own 100% of our general partner. In addition to the 2% general partner interest in us, our general partner will own the incentive distribution rights. Upon the closing of this offering, Wexford Funds will own 27,925,200 common units and 3,741,500 subordinated units.

Contribution Agreement

In connection with the closing of this offering, we will enter into a contribution agreement that will effect the transactions, including the transfer of the ownership interests in Rhino Energy LLC, and the use of the net proceeds of this offering. This agreement will not be the result of arm's-length negotiations, and it, or any of the transactions that it provides for, may not be effected on terms at least as favorable to the parties to this agreement as could have been obtained from unaffiliated third parties. All of the transaction expenses incurred in connection with these transactions will be paid from the proceeds of this offering.

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Colorado Mining Agreement

We have entered into a contract mining agreement with CAM-Colorado LLC. In connection with the closing of this offering, Rhino Energy LLC will distribute its ownership interests in CAM-Colorado LLC to NR Energy LLC. CAM-Colorado LLC holds four coal leases with the BLM as well as other real property rights related to the McClane Canyon mine near Loma, Colorado. We own the equipment, operating permits and a haul road related to the operation of the McClane Canyon mine. Pursuant to the agreement, we will mine up to 1.5 million tons of saleable coal from the McClane Canyon mine. The agreement will expire the earlier of (1) March 31, 2011 or (2) at such time as we have mined 1.5 million tons of coal from the McClane Canyon mine. We will pay all operating costs, employee costs, fees, taxes and royalties relating to the operation of the mine, and will pay to CAM-Colorado LLC compensation of $0.50 per ton. We have the right to sell the coal we produce and retain the proceeds of such sale. At the expiration of the term of the contract mining agreement, we will have the obligation to fully reclaim the mine, unless we are notified by CAM-Colorado LLC that it desires to keep the McClane Canyon mine open after expiration of the contract mining agreement and agrees to assume all reclamation obligations, including the assumption of all mining permits and the replacement of all bonds posted by us.

This agreement is not the result of arm's-length negotiations and may not have been effected on terms at least as favorable to the parties to this agreement as could have been obtained from unaffiliated third parties.

Shared Services Agreement

Upon the closing of this offering, we will enter into a shared services agreement with Rhino GP LLC and NR Energy LLC. Under this agreement, we, our subsidiaries or our general partner will provide NR Energy LLC with certain advisory, operational and administrative support. These services will be provided in a commercially reasonable manner and upon the reasonable request of NR Energy LLC. We or our general partner will provide these services directly but may subcontract for certain of these services with other entities. NR Energy LLC will pay a reasonable fee to us or our general partner, as applicable, that will include reimbursement of the reasonable cost of any direct and indirect expenses we or our general partner incur in providing these services, including services such as development and maintenance of coal properties.

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CONFLICTS OF INTEREST AND FIDUCIARY DUTIES

Conflicts of Interest

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

Whenever a conflict arises between our general partner or its affiliates, on the one hand, and us or any other partner, on the other, our general partner will resolve that conflict. Our partnership agreement contains provisions that modify and limit our general partner's fiduciary duties to the unitholders. Our partnership agreement also restricts the remedies available to unitholders for actions taken that, without those limitations, might constitute breaches of fiduciary duty.

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

•: approved by the conflicts committee, although our general partner is not obligated to seek such approval;
•: approved by the vote of a majority of the outstanding common units, excluding any common units owned by our general partner or any of its affiliates;
•: on terms no less favorable to us than those generally being provided to or available from unrelated third parties; or
•: fair and reasonable to us, taking into account the totality of the relationships between the parties involved, including other transactions that may be particularly favorable or advantageous to us.

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

Conflicts of interest could arise in the situations described below, among others.

Our general partner's affiliates 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 or those activities incidental to its ownership of interests in us. Except as provided in our partnership agreement, affiliates of our general partner, including Wexford and its investment funds, are not prohibited from engaging in other businesses or activities, including those that might be in direct competition with us. Wexford, through its investment funds and managed accounts, make investments and purchase entities in the coal and oil and natural gas sectors. These investments and acquisitions may include entities or assets that we would

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have been interested in acquiring. Pursuant to the terms of our partnership agreement, the doctrine of corporate opportunity, or any analogous doctrine, shall not apply to our general partner or any of its affiliates, including its executive officers, directors and Wexford. 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. The above provisions will not apply to the members of management at Rhino Energy LLC who are responsible for our coal operations. Such persons will be obligated to present corporate opportunities to us. Therefore, Wexford may compete with us for investment opportunities and Wexford may own an interest in entities that compete with us on an operations basis.

Our general partner is allowed to take into account the interests of parties other than us such as the Wexford Principals in resolving conflicts.

Our partnership agreement contains provisions that reduce the 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. This entitles our general partner to consider only the interests and factors that it desires, and it has no duty or obligation to give any consideration to any interest of, or factors affecting, us, our affiliates or any limited partner. Examples include the exercise of its limited call right, its voting rights with respect to the units it owns, its registration rights and its determination whether or not to consent to any merger or consolidation of the partnership.

We will rely solely on the executive management personnel of our general partner.

Nicholas R. Glancy, Richard A. Boone, David G. Zatezalo, Christopher N. Moravec and Thomas Hanley are employees of Rhino GP LLC. Each will devote substantially all of their time to our business and affairs. Mark D. Zand, Jay L. Maymudes and Arthur H. Amron are employees of Wexford and will devote a portion of their time to our business and affairs. None of our executive management personnel is required to work full time on our business and affairs. Affiliates of our general partner will conduct business and activities of their own in which we will have no economic interest. If these separate activities are significantly greater than our activities, there could be material competition for the time and effort of our executive management personnel who provide services to affiliates of our general partner, such as Wexford.

Our general partner has limited its liability and reduced its fiduciary duties, and has also restricted the remedies available to our unitholders for actions that, without these limitations, might constitute breaches of fiduciary duty.

In addition to the provisions described above, our partnership agreement contains provisions that restrict the remedies available to our unitholders for actions that might otherwise constitute breaches of fiduciary duty. For example, our partnership agreement:

•: provides that our general partner shall 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 it believed that the decision was in the best interests of our partnership;
•: generally provides that affiliated transactions and resolutions of conflicts of interest not approved by the conflicts committee of the board of directors of our general partner and not involving a vote of unitholders must be on terms no less favorable to us than those generally being provided to or available from unrelated third parties or be "fair and reasonable" to us, as

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determined by our general partner in good faith, and that, in determining whether a transaction or resolution is "fair and reasonable," our general partner may consider the totality of the relationships between the parties involved, including other transactions that may be particularly advantageous or beneficial to us; and

•: provides that our general partner and its executive officers and directors will not be liable for monetary damages to us, our limited partners or assignees for any acts or omissions unless there has been a final and non-appealable judgment entered by a court of competent jurisdiction determining that our general partner or those other persons acted in bad faith or engaged in fraud or willful misconduct.

Actions taken by our general partner may affect the amount of cash available for distribution to unitholders or accelerate the right to convert subordinated units.

The amount of cash that is available for distribution to unitholders is affected by decisions of our general partner regarding such matters as:

•: amount and timing of asset purchases and sales;
•: cash expenditures;
•: borrowings;
•: issuance of additional units; and
•: the creation, reduction, or increase of reserves in any quarter.

In addition, borrowings by us and our affiliates do not constitute a breach of any duty owed by our general partner to our unitholders, including borrowings that have the purpose or effect of:

•: enabling our general partner or its affiliates to receive distributions on any subordinated units held by them or the incentive distribution rights; or
•: hastening the expiration of the subordination period.

For example, in the event we have not generated sufficient cash from our operations to pay the minimum quarterly distribution on our common units and our subordinated units, our partnership agreement permits us to borrow funds, which would enable us to make this distribution on all outstanding units. Please read "How We Make Cash Distributions—Subordination Period."

Our partnership agreement provides that we and our subsidiaries may borrow funds from our general partner and its affiliates. Our general partner and its affiliates may not borrow funds from us, our operating company, or its operating subsidiaries.

We will reimburse our general partner and its affiliates for expenses.

We will reimburse our general partner and its affiliates for costs incurred in managing and operating us, including costs incurred in rendering corporate staff and support services to us. Our partnership agreement provides that our general partner will determine the expenses that are allocable to us in good faith. Wexford will charge on a fully allocated cost basis for services provided to us, other than legal support which will be on an hourly basis. This fully allocated cost basis is based on the percentage of time spent by Wexford personnel on our matters and includes the compensation paid by Wexford to such persons and their allocated overhead. The allocation of compensation expense for those executive officers of our general partner who are employees of Wexford will be determined based on a good faith estimate of the value of each such executive officer's services performed on our business and affairs, subject to the approval of the audit committee of our general partner. The fully

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allocated basis charged by Wexford does not include a profit component. Please read "Certain Relationships and Related Party Transactions."

Contracts between us, on the one hand, and our general partner and its affiliates, on the other, will not be the result of arm's-length negotiations.

Our partnership agreement allows our general partner to determine, in good faith, any amounts to pay itself or its affiliates for any services rendered to us. Our general partner may also enter into additional contractual arrangements with any of its affiliates on our behalf. Neither our partnership agreement nor any of the other agreements, contracts, and arrangements between us and our general partner and its affiliates are or will be the result of arm's-length negotiations.

Our general partner will determine, in good faith, the terms of any of these transactions entered into after the sale of the common units offered in this offering.

Our general partner and its affiliates will have no obligation to permit us to use any facilities or assets of our general partner and its affiliates, except as may be provided in contracts entered into specifically dealing with that use. There is no obligation of our general partner and its affiliates to enter into any contracts of this kind.

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 other party has recourse only to our assets and not against our general partner or its assets or any affiliate of our general partner or its assets. Our partnership agreement provides that any action taken by our general partner to limit its or our liability is not a breach of our general partner's fiduciary duties, even if we could have obtained terms that are more favorable without the limitation on liability.

Common units are subject to our general partner's limited call right.

Our general partner may exercise its right to call and purchase common units as provided in the partnership agreement or assign this right to one of its affiliates or to us. Our general partner may use its own discretion, free of fiduciary duty restrictions, in determining whether to exercise this right. As a result, a common unitholder may have his common units purchased from him at an undesirable time or price. Please read "The Partnership Agreement—Limited Call Right."

Common unitholders will have no right to enforce obligations of our general partner and its affiliates under agreements with us.

Any agreements between us, on the one hand, and our general partner and its affiliates, on the other, will not grant to the unitholders, separate and apart from us, the right to enforce the obligations of our general partner and its affiliates in our favor.

Our general partner decides whether to retain separate counsel, accountants or others to perform services for us.

The attorneys, independent accountants and others who perform services for us have been retained by our general partner. Attorneys, independent accountants and others who perform services for us are selected by our general partner or the conflicts committee and may perform services for our general partner and its affiliates. We may retain separate counsel for ourselves or the holders of common units in the event of a conflict of interest between our general partner and its affiliates, on the one hand, and us or the holders of common units, on the other, depending on the nature of the conflict. We do not intend to do so in most cases.

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Fiduciary Duties

Our general partner is accountable to us and our unitholders as a fiduciary. Fiduciary duties owed to unitholders by our general partner are prescribed by law and the partnership agreement. The Delaware Act 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 contains various provisions restricting the fiduciary duties that might otherwise be owed by our general partner. We have adopted these provisions to allow our general partner or its affiliates to engage in transactions with us that would otherwise be prohibited by state-law fiduciary standards and to take into account the interests of other parties in addition to our interests when resolving conflicts of interest. Without such modifications, such transactions could result in violations of our general partner's state-law fiduciary duty standards. We believe this is appropriate and necessary because the board of directors of our general partner has fiduciary duties to manage our general partner in a manner beneficial both to its owners, as well as to our unitholders. Without these modifications, our general partner's ability to make decisions involving conflicts of interest would be restricted. The modifications to the fiduciary standards enable our general partner to take into consideration all parties involved in the proposed action, so long as the resolution is fair and reasonable to us. These modifications also enable our general partner to attract and retain experienced and capable directors. These modifications disadvantage the common unitholders because they restrict the rights and remedies that would otherwise be available to unitholders for actions that, without those limitations, might constitute breaches of fiduciary duty, as described below, and permit our general partner to take into account the interests of third parties in addition to our interests when resolving conflicts of interest. The following is a summary of the material restrictions of the fiduciary duties owed by our general partner to the limited partners:

State law fiduciary duty standards		Fiduciary duties are generally considered to include an obligation to act in good faith and with due care and loyalty. The duty of care, in the absence of a provision in a partnership agreement providing otherwise, would generally require a general partner to act for the partnership in the same manner as a prudent person would act on his own behalf. The duty of loyalty, in the absence of a provision in a partnership agreement providing otherwise, would generally prohibit a general partner of a Delaware limited partnership from taking any action or engaging in any transaction where a conflict of interest is present.
Partnership agreement modified standards		Our partnership agreement contains provisions that waive or consent to conduct by our general partner and its affiliates that might otherwise raise issues as to compliance with fiduciary duties or applicable law. For example, our partnership agreement provides that when our general partner is acting in its capacity as our general partner, as opposed to in its individual capacity, it must act in "good faith" and will not be subject to any other standard under applicable law. In addition, when our general partner is acting in its individual capacity, as opposed to in its capacity as our general partner, it may act without any fiduciary obligation to us or the unitholders whatsoever. These standards reduce the obligations to which our general partner would otherwise be held.

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	Our partnership agreement generally provides that affiliated transactions and resolutions of conflicts of interest not involving a vote of unitholders or that are not approved by the conflicts committee of the board of directors of our general partner must be:
	•	on terms no less favorable to us than those generally being provided to or available from unrelated third parties; or
	•	"fair and reasonable" to us, taking into account the totality of the relationships between the parties involved (including other transactions that may be particularly favorable or advantageous to us).
	If our general partner does not seek approval from the conflicts committee and its board of directors determines that the resolution or course of action taken with respect to the conflict of interest satisfies either of the standards set forth in the bullet points above, then it will be presumed that, in making its decision, the board of directors, which may include board members affected by the conflict of interest, 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. These standards reduce the obligations to which our general partner would otherwise be held.
	In addition to the other more specific provisions limiting the obligations of our general partner, our partnership agreement further provides that our general partner and its officers and directors will not be liable for monetary damages to us, our limited partners or assignees for errors of judgment or for any acts or omissions unless there has been a final and non-appealable judgment by a court of competent jurisdiction determining that our general partner or its officers and directors acted in bad faith or engaged in fraud, willful misconduct or gross negligence.
Rights and remedies of unitholders	The Delaware Act generally provides that a limited partner may institute legal action on behalf of the partnership to recover damages from a third party where a general partner has refused to institute the action or where an effort to cause a general partner to do so is not likely to succeed. These actions include actions against a general partner for breach of its fiduciary duties or of the partnership agreement. In addition, the statutory or case law of some jurisdictions may permit a limited partner to institute legal action on behalf of himself and all other similarly situated limited partners to recover damages from a general partner for violations of its fiduciary duties to the limited partners.

In order to become one of our limited partners, a common unitholder is required to agree to be bound by the provisions in the partnership agreement, including the provisions discussed above. Please

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read "Description of the Common Units—Transfer of Common Units." This is in accordance with the policy of the Delaware Act favoring the principle of freedom of contract and the enforceability of partnership agreements. The failure of a limited partner or assignee to sign a partnership agreement does not render the partnership agreement unenforceable against that person.

Under our partnership agreement, we must indemnify our general partner and its officers, directors and managers, to the fullest extent permitted by law, against liabilities, costs and expenses incurred by our general partner or these other persons. We must provide this indemnification unless there has been a final and non-appealable judgment by a court of competent jurisdiction determining that these persons acted in bad faith or engaged in fraud, willful misconduct or gross negligence. We also must provide this indemnification for criminal proceedings when our general partner or these other persons acted with no reasonable cause to believe that their conduct was unlawful. Thus, our general partner could be indemnified for its negligent acts if it met the requirements set forth above. To the extent that these provisions purport to include indemnification for liabilities arising under the Securities Act of 1933, in the opinion of the SEC, such indemnification is contrary to public policy and therefore unenforceable. Please read "The Partnership Agreement—Indemnification."

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DESCRIPTION OF THE COMMON UNITS

The Units

The common units represent limited partner interests in us. The holders of common units and subordinated units are entitled to participate in partnership distributions and are entitled to exercise the rights or privileges available to limited partners under our partnership agreement. For a description of the relative rights and preferences of holders of common units and subordinated units and our general partner in and to partnership distributions, please read this section and "How We Make Cash Distributions." For a description of the rights and privileges of limited partners under our partnership agreement, including voting rights, please read "The Partnership Agreement."

Transfer Agent and Registrar

Duties

American Stock Transfer and Trust Company will serve as registrar and transfer agent for the common units. We pay all fees charged by the transfer agent for transfers of common units, except the following that must be paid by unitholders:

•: surety bond premiums to replace lost or stolen certificates, or to cover taxes and other governmental charges in connection therewith;
•: special charges for services requested by a holder of a common unit; and
•: other similar fees or charges.

There is no charge to unitholders for disbursements of our cash distributions. We will indemnify the transfer agent, its agents and each of their respective stockholders, directors, officers and employees against all claims and losses that may arise out of acts performed or omitted for its activities in that capacity, except for any liability due to any gross negligence or intentional misconduct of the indemnified person or entity.

Resignation or Removal

The transfer agent may resign, by notice to us, or be removed by us. The resignation or removal of the transfer agent will become effective upon our appointment of a successor transfer agent and registrar and its acceptance of the appointment. If no successor has been appointed and has accepted the appointment within 30 days after notice of the resignation or removal, our general partner may act as the transfer agent and registrar until a successor is appointed.

Transfer of Common Units

The transfer of the common units to persons that purchase directly from the underwriters will be accomplished through the proper completion, execution and delivery of a transfer application by the investor. Any later transfers of a common unit will not be recorded by the transfer agent or recognized by us unless the transferee executes and delivers a properly completed transfer application. By executing and delivering a transfer application, the transferee of common units:

•: becomes the record holder of the common units and is an assignee until admitted into our partnership as a limited partner;
•: automatically requests admission as a limited partner in our partnership;
•: executes and agrees to be bound by the terms and conditions of our partnership agreement;
•: represents that the transferee has the capacity, power and authority to enter into the partnership agreement;

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•: grants powers of attorney to the executive officers of our general partner and any liquidator of us as specified in the partnership agreement; and
•: gives the consents, covenants, representations and approvals contained in our partnership agreement, such as the approval of all transactions and agreements we are entering into in connection with our formation and this offering.

An assignee will become a limited partner of our partnership for the transferred common units automatically upon the recording of the transfer on our books and records. Our general partner will cause any unrecorded transfers for which a properly completed and duly executed transfer application has been received to be recorded on our books and records no less frequently than quarterly.

A transferee's broker, agent or nominee may complete, execute and deliver a transfer application. We are entitled to treat the nominee holder of a common unit as the absolute owner. In that case, the beneficial holder's rights are limited solely to those that it has against the nominee holder as a result of any agreement between the beneficial owner and the nominee holder.

Common units are securities and are transferable according to the laws governing transfer of securities. In addition to other rights acquired upon transfer, the transferor gives the transferee the right to request admission as a limited partner in our partnership for the transferred common units. A purchaser or transferee of common units who does not execute and deliver a properly completed transfer application obtains only:

•: the right to assign the common unit to a purchaser or other transferee; and
•: the right to transfer the right to seek admission as a limited partner in our partnership for the transferred common units.

Thus, a purchaser or transferee of common units who does not execute and deliver a properly completed transfer application:

•: will not receive cash distributions;
•: will not be allocated any of our income, gain, deduction, losses or credits for federal income tax or other tax purposes;
•: may not receive some federal income tax information or reports furnished to record holders of common units; and
•: will have no voting rights;

unless the common units are held in a nominee or "street name" account and the nominee or broker has executed and delivered a transfer application and certification as to itself and any beneficial holders.

The transferor of common units has a duty to provide the transferee with all information that may be necessary to transfer the common units. The transferor does not have a duty to ensure the execution of the transfer application by the transferee and has no liability or responsibility if the transferee neglects or chooses not to execute and deliver a properly completed transfer application to the transfer agent. Please read "The Partnership Agreement—Status as Limited Partner or Assignee."

Until a common unit has been transferred on our books, we and the transfer agent may treat the record holder of the unit as the absolute owner for all purposes, except as otherwise required by law or stock exchange regulations.

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THE PARTNERSHIP AGREEMENT

The following is a summary of the material provisions of our partnership agreement. The form of our partnership agreement is included in this prospectus as Appendix A. We will provide prospective investors with a copy of this agreement upon request at no charge.

We summarize the following provisions of our partnership agreement elsewhere in this prospectus:

•: with regard to distributions of available cash, please read "How We Make Cash Distributions;"
•: with regard to the fiduciary duties of our general partner, please read "Conflicts of Interest and Fiduciary Duties;"
•: with regard to the transfer of common units, please read "Description of the Common Units—Transfer of Common Units;" and
•: with regard to allocations of taxable income and taxable loss, please read "Material Tax Consequences."

Organization and Duration

We were organized on January 11, 2006 and have a perpetual existence.

Purpose

Our purpose under the partnership agreement is limited to any business activities that are approved by our general partner, in its sole discretion, and in any event that lawfully may be conducted by a limited partnership organized under Delaware law; provided that our general partner may not cause us to engage, directly or indirectly, in any business activity that our general partner determines would cause us to be treated as an association taxable as a corporation or otherwise taxable as an entity for federal income tax purposes.

Although our general partner, in its individual capacity, has the power to cause us, our operating company or its subsidiaries to engage in activities other than coal mining and marketing, and limestone mining ancillary to our coal mining operations, our general partner may decline to do so free of any fiduciary duty or obligation whatsoever to us or the limited partners, including any duty to act in good faith or in the best interests of us or the limited partners. However, any decision by our general partner to cause us or our subsidiaries to invest in activities will be subject to its fiduciary duties as modified by our partnership agreement. In general, our general partner is authorized in general to perform all acts it determines to be necessary or appropriate to carry out our purposes and to conduct our business.

Power of Attorney

Each limited partner and each person who acquires a unit from a unitholder and executes and delivers a transfer application and certification, grants to our general partner and, if appointed, a liquidator, a power of attorney to, among other things, execute and file documents required for our qualification, continuance, or dissolution. The power of attorney also grants our general partner the authority to amend, and to make consents and waivers under, our partnership agreement.

Capital Contributions

Unitholders are not obligated to make additional capital contributions, except as described below under "—Limited Liability."

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Voting Rights

The following matters require the limited partner vote specified below. Various matters require the approval of a "unit majority," which means:

•: during the subordination period, the approval of a majority of the outstanding common units, excluding those common units held by our general partner and its affiliates, and a majority of the outstanding subordinated units, voting as separate classes; and
•: after the subordination period, the approval of a majority of the outstanding common units.

By virtue of the exclusion of those common units held by our general partner and its affiliates from the required vote, and by their ownership of all of the subordinated units, during the subordination period our general partner and its affiliates do not have the ability to ensure passage of, but do have the ability to ensure defeat of, any amendment that requires a unit majority.

In voting their common and subordinated units, our general partner and its affiliates will have no fiduciary duty or obligation whatsoever to us or the limited partners, including any duty to act in good faith or in the best interests of us and our limited partners.

Issuance of additional units		No approval rights.
Amendment of our partnership agreement		Certain amendments may be made by our general partner without the approval of the limited partners. Other amendments generally require the approval of a unit majority. Please read "—Amendment of Our Partnership Agreement."
Merger of our partnership or the sale of all or substantially all of our assets		Unit majority in certain circumstances. Please read "—Merger, Sale or Other Disposition of Assets."
Continuation of our partnership upon dissolution		Unit majority. Please read "—Termination and Dissolution."
Withdrawal of our general partner		Under most circumstances, the approval of a majority of the common units, excluding common units held by our general partner and its affiliates, is required for the withdrawal of our general partner prior to June 30, 2018 in a manner that would cause a dissolution of our partnership. Please read "—Withdrawal or Removal of Our General Partner."
Removal of our general partner		Not less than 66²/3% of the outstanding common units and subordinated units, voting as a single class, including common units and subordinated units held by our general partner and its affiliates. Please read "—Withdrawal or Removal of Our General Partner."

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Transfer of our general partner interest		Our general partner may transfer all, but not less than all, of its general partner interest in us without a vote of our limited partners to an affiliate or to another person in connection with its merger or consolidation with or into, or sale of all or substantially all of its assets to, such person. The approval of a majority of the outstanding common units, excluding common units held by our general partner and its affiliates, is required in other circumstances for a transfer of the general partner interest to a third party prior to June 30, 2018. Please read "—Transfer of General Partner Interest."
Transfer of incentive distribution rights		Except for transfers to an affiliate or another person in connection with our general partner's merger or consolidation with or into or sale of all or substantially all of its assets to, such person, the approval of a majority of the outstanding common units, excluding common units held by our general partner and its affiliates, voting separately as a class, is required in most circumstances for a transfer of the incentive distribution rights to a third party prior to June 30, 2018. Please read "—Transfer of Incentive Distribution Rights."
Transfer of ownership interests in our general partner		No approval required at any time. Please read "—Transfer of Ownership Interests in Our General Partner."

Limited Liability

Assuming that a limited partner does not participate in the control of our business within the meaning of the Delaware Act and that it otherwise acts in conformity with the provisions of our partnership agreement, its liability under the Delaware Act will be limited, subject to possible exceptions, to the amount of capital he is obligated to contribute to us for its common units plus its share of any undistributed profits and assets. If it were determined, however, that the right of, or exercise of the right by, the limited partners as a group:

•: to remove or replace our general partner;
•: to approve some amendments to our partnership agreement; or
•: to take other action under our partnership agreement;

constituted "participation in the control" of our business for the purposes of the Delaware Act, then the limited partners could 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 who reasonably believe 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. While this does not mean that a limited partner could not seek legal recourse, we know of no precedent for such a claim in Delaware case law.

Under the Delaware Act, a limited partnership may not make a distribution to a partner if, after the distribution, all liabilities of the limited partnership, other than liabilities to partners on account of their partnership interests and liabilities for which the recourse of creditors is limited to specific property of the partnership, would exceed the fair value of the assets of the limited partnership. For

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the purpose of determining the fair value of the assets of a limited partnership, the Delaware Act provides that the fair value of property subject to liability for which recourse of creditors is limited shall be included in the assets of the limited partnership only to the extent that the fair value of that property exceeds the nonrecourse liability. The Delaware Act provides that a limited partner who receives a distribution and knew at the time of the distribution that the distribution was in violation of the Delaware Act shall be liable to the limited partnership for the amount of the distribution for three years. Under the Delaware Act, an assignee who becomes a limited partner of a limited partnership is liable for the obligations of its assignor to make contributions to the partnership, except the assignee is not obligated for liabilities unknown to him at the time he became a limited partner and that could not be ascertained from the partnership agreement.

As of December 31, 2007, our subsidiaries conducted business in Colorado, Illinois, Kentucky, Ohio and West Virginia. Our subsidiaries may conduct business in other states in the future. Maintenance of our limited liability as a member of our operating company may require compliance with legal requirements in the jurisdictions in which our operating company conducts business, including qualifying our subsidiaries to do business there.

Limitations on the liability of limited partners for the obligations of a limited partnership have not been clearly established in many jurisdictions. If, by virtue of our membership interest in our operating company or otherwise, it were determined that we were conducting business in any state without compliance with the applicable limited partnership or limited liability company statute, or that the right or exercise of the right by the limited partners as a group to remove or replace our general partner, to approve some amendments to our partnership agreement, or to take other action under our partnership agreement constituted "participation in the control" of our business for purposes of the statutes of any relevant jurisdiction, then the limited partners could be held personally liable for our obligations under the law of that jurisdiction to the same extent as the general partner under the circumstances. We will operate in a manner that our general partner considers reasonable and necessary or appropriate to preserve the limited liability of the limited partners.

Issuance of Additional Securities

Our partnership agreement authorizes us to issue an unlimited number of additional partnership securities for the consideration and on the terms and conditions determined by our general partner without the approval of the unitholders.

It is possible that we will fund acquisitions through the issuance of additional common units, subordinated units or other partnership securities. Holders of any additional common units we issue will be entitled to share equally with the then-existing holders of common units in our distributions of available cash. In addition, the issuance of additional common units or other partnership securities may dilute the value of the interests of the then-existing holders of common units in our net assets.

In accordance with Delaware law and the provisions of our partnership agreement, we may also issue additional partnership securities that, as determined by our general partner, may have special voting rights to which the common units are not entitled. In addition, our partnership agreement does not prohibit the issuance by our subsidiaries of equity securities, which may effectively rank senior to the common units.

Our general partner's interest in us is represented by unit equivalents for allocation and distribution purposes. Upon issuance of additional partnership securities, our general partner will have the right, but not the obligation, to make additional capital contributions to us to the extent necessary to maintain its general partner interest. Our general partner's initial 2% interest in us will thus be reduced if we issue additional partnership securities in the future and our general partner does not elect to maintain its initial 2% general partner interest. In addition, our general partner will have the right, which it may from time to time assign in whole or in part to any of its affiliates, to purchase

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common units, subordinated units or other partnership securities to the extent necessary to maintain its and its affiliates' limited partner percentage interest in us, whenever, and on the same terms that, we issue those securities to persons other than our general partner and its affiliates. The holders of common units will not have preemptive rights to acquire additional common units or other partnership securities.

Amendment of Our Partnership Agreement

General

Amendments to our partnership agreement may be proposed only by our general partner. However, our general partner will have no duty or obligation to propose any amendment and may decline to do so free of any fiduciary duty or obligation whatsoever to us or the limited partners, including any duty to act in good faith or in the best interests of us or the limited partners. In order to adopt a proposed amendment, other than the amendments discussed below, our general partner must seek written approval of the holders of the number of units required to approve the amendment or call a meeting of the limited partners to consider and vote upon the proposed amendment. Except as described below, an amendment must be approved by a unit majority.

Prohibited Amendments

No amendment may:

(1): enlarge the obligations of any limited partner without its consent, unless approved by at least a majority of the type or class of limited partner interests so affected; or
(2): enlarge the obligations of, restrict in any way any action by or rights of, or reduce in any way the amounts distributable, reimbursable or otherwise payable by us to our general partner or any of its affiliates without the consent of our general partner, which may be given or withheld at its option.

The provision of our partnership agreement preventing the amendments having the effects described in clauses (1) and (2) above can be amended upon the approval of the holders of at least 90% of the outstanding units voting together as a single class (including units owned by our general partner and its affiliates). Upon the consummation of this offering, affiliates of our general partner will own 86.4% of the outstanding common and subordinated units (or 84.6% of the outstanding common and subordinated units, if the underwriters exercise their option to purchase additional common units in full).

No Unitholder Approval

Our general partner may generally make amendments to the partnership agreement without the approval of any limited partner or assignee to reflect:

(1): a change in our name, the location of our principal place of business, our registered agent or our registered office;
(2): the admission, substitution, withdrawal, or removal of partners in accordance with our partnership agreement;
(3): a change that our general partner determines to be necessary or appropriate for us to qualify or to continue our qualification as a limited partnership or a partnership in which the limited partners have limited liability under the laws of any state or to ensure that neither we, our operating company, nor its subsidiaries will be treated as an association taxable as a corporation or otherwise taxed as an entity for federal income tax purposes;

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(4): an amendment that is necessary, in the opinion of our counsel, to prevent us or our general partner or its directors, officers, agents, or trustees from in any manner being subjected to the provisions of the Investment Company Act of 1940, the Investment Advisors Act of 1940, or "plan asset" regulations adopted under the Employee Retirement Income Security Act of 1974 ("ERISA"), whether or not substantially similar to plan asset regulations currently applied or proposed;
(5): an amendment that our general partner determines to be necessary or appropriate for the authorization of additional partnership securities or rights to acquire partnership securities;
(6): any amendment expressly permitted in our partnership agreement to be made by our general partner acting alone;
(7): an amendment effected, necessitated, or contemplated by a merger agreement that has been approved under the terms of our partnership agreement;
(8): any amendment that our general partner determines to be necessary or appropriate for the formation by us of, or our investment in, any corporation, partnership, or other entity, as otherwise permitted by our partnership agreement;
(9): a change in our fiscal year or taxable year and related changes;
(10): mergers with or conveyances to another limited liability entity that is newly formed and has no assets, liabilities or operations at the time of the merger or conveyance other than those it receives by way of the merger or conveyance; or
(11): any other amendments substantially similar to any of the matters described above.

In addition, our general partner may make amendments to the partnership agreement without the approval of any limited partner or assignee if our general partner determines that those amendments:

(1): do not adversely affect the limited partners (or any particular class of limited partners) in any material respect;
(2): are necessary or appropriate to satisfy any requirements, conditions, or guidelines contained in any opinion, directive, order, ruling, or regulation of any federal or state agency or judicial authority or contained in any federal or state statute;
(3): are necessary or appropriate to facilitate the trading of limited partner interests or to comply with any rule, regulation, guideline, or requirement of any securities exchange on which the limited partner interests are or will be listed for trading;
(4): are necessary or appropriate for any action taken by our general partner relating to splits or combinations of units under the provisions of our partnership agreement; or
(5): are required to effect the intent expressed in this prospectus or the intent of the provisions of our partnership agreement or are otherwise contemplated by our partnership agreement.

Opinion of Counsel and Limited Partner Approval

Our general partner will not be required to obtain an opinion of counsel that an amendment will not result in a loss of limited liability to the limited partners or result in our being treated as an entity for federal income tax purposes in connection with any of the amendments described above under "—No Unitholder Approval." No other amendments to our partnership agreement will become effective without the approval of holders of at least 90% of the outstanding units voting as a single class unless we first obtain an opinion of counsel to the effect that the amendment will not affect the limited liability under applicable law of any of our limited partners. Finally, our general partner may consummate any merger without the prior approval of our limited partners if we are the surviving

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entity in the transaction, the transaction would not result in a material amendment to our partnership agreement, each of our units will be an identical unit of our partnership following the transaction, the units to be issued do not exceed 20% of our outstanding units immediately prior to the transaction and our general partner has received an opinion of counsel regarding certain limited liability and tax matters.

In addition to the above restrictions, any amendment that would have a material adverse effect on the rights or preferences of any type or class of outstanding units in relation to other classes of units will require the approval of at least a majority of the type or class of units so affected. Any amendment that reduces the voting percentage required to take any action must be approved by the affirmative vote of limited partners whose aggregate outstanding units constitute not less than the voting requirement sought to be reduced.

Merger, Sale or Other Disposition of Assets

A merger or consolidation of us requires the prior consent of our general partner. However, our general partner will have no duty or obligation to consent to any merger or consolidation and may decline to do so free of any fiduciary duty or obligation whatsoever to us or the limited partners, including any duty to act in good faith or in the best interest of us or the limited partners.

In addition, our partnership agreement generally prohibits our general partner, without the prior approval of the holders of units representing a unit majority, from causing us to, among other things, sell, exchange, or otherwise dispose of all or substantially all of our assets in a single transaction or a series of related transactions, including by way of merger, consolidation, or other combination, or approving on our behalf the sale, exchange, or other disposition of all or substantially all of the assets of our subsidiaries. Our general partner may, however, mortgage, pledge, hypothecate, or grant a security interest in all or substantially all of our assets without that approval. Our general partner may also sell all or substantially all of our assets under a foreclosure or other realization upon those encumbrances without that approval.

If the conditions specified in our partnership agreement are satisfied, our general partner may convert us or any of our subsidiaries into a new limited liability entity or merge us or any of our subsidiaries into, or convey some or all of our assets to, a newly formed entity if the sole purpose of that merger or conveyance is to effect a mere change in our legal form into another limited liability entity. The limited partners are not entitled to dissenters' rights of appraisal under our partnership agreement or applicable Delaware law in the event of a conversion, merger or consolidation, a sale of substantially all of our assets, or any other transaction or event.

Termination and Dissolution

We will continue as a limited partnership until terminated under our partnership agreement. We will dissolve upon:

(1): the election of our general partner to dissolve us, if approved by the holders of units representing a unit majority;
(2): the sale, exchange or other disposition of all or substantially all of our assets and properties and our subsidiaries;
(3): the entry of a decree of judicial dissolution of our partnership; or
(4): the withdrawal or removal of our general partner or any other event that results in its ceasing to be our general partner other than by reason of a transfer of its general partner interest in accordance with our partnership agreement or withdrawal or removal following approval and admission of a successor.

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Upon a dissolution under clause (4), the holders of a unit majority may also elect, within specific time limitations, to reconstitute us and continue our business on the same terms and conditions described in our partnership agreement by forming a new limited partnership on terms identical to those in our partnership agreement and having as general partner an entity approved by the holders of units representing a unit majority, subject to our receipt of an opinion of counsel to the effect that:

•: the action would not result in the loss of limited liability under Delaware law of any limited partner; and
•: neither our partnership nor any of our subsidiaries would be treated as an association taxable as a corporation or otherwise be taxable as an entity for federal income tax purposes upon the exercise of that right to continue (to the extent not already so treated or taxed).

Liquidation and Distribution of Proceeds

Upon our dissolution, unless we are reconstituted and continued as a new limited partnership, the liquidator authorized to wind up our affairs will, acting with all of the powers of our general partner that are necessary or appropriate, liquidate our assets and apply the proceeds of the liquidation as described in "How We Make Cash Distributions—Distributions of Cash Upon Liquidation." The liquidator may defer liquidation or distribution of our assets for a reasonable period of time or distribute assets to partners in kind if it determines that a sale would be impractical or would cause undue loss to our partners.

Withdrawal or Removal of Our General Partner

Except as described below, our general partner has agreed not to withdraw voluntarily as our general partner prior to June 30, 2018 without obtaining the approval of the holders of at least a majority of the outstanding common units, excluding common units held by our general partner and its affiliates, and furnishing an opinion of counsel regarding limited liability and tax matters. On or after June 30, 2018, our general partner may withdraw as general partner without first obtaining approval of any unitholder by giving 90 days' written notice, and that withdrawal will not constitute a violation of our partnership agreement. Notwithstanding the information above, our general partner may withdraw without common unitholder approval upon 90 days' notice to the limited partners if at least 50% of the outstanding common units are held or controlled by one person and its affiliates other than our general partner and its affiliates. In addition, our partnership agreement permits our general partner in some instances to sell or otherwise transfer all of its general partner interest in us without the approval of the limited partners. Please read "—Transfer of General Partner Interest" and "—Transfer of Incentive Distribution Rights."

Upon withdrawal of our general partner under any circumstances, other than as a result of a transfer by our general partner of all or a part of its general partner interest in us, the holders of a majority of the outstanding common units and subordinated units, voting as separate classes, may select a successor to that withdrawing general partner. If a successor is not elected, or is elected but an opinion of counsel regarding limited liability and tax matters cannot be obtained, we will be dissolved, wound up, and liquidated, unless within a specified period of time after that withdrawal, the holders of a unit majority agree in writing to continue our business and to appoint a successor general partner. Please read "—Termination and Dissolution."

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Our general partner may not be removed unless that removal is approved by the vote of the holders of not less than 66²/3% of the outstanding common units and subordinated units, voting together as a single class, including units held by our general partner and its affiliates, and we receive an opinion of counsel regarding limited liability and tax matters. Any removal of our general partner is also subject to the approval of a successor general partner by the vote of the holders of a majority of the outstanding common units and subordinated units, voting as separate classes. The ownership of more than 33¹/3% of the outstanding common units and subordinated units by our general partner and its affiliates would give them the practical ability to prevent our general partner's removal. At the closing of this offering, an affiliate of our general partner will own 86.4% of the outstanding common and subordinated units (or 84.6% of the outstanding common and subordinated units, if the underwriters exercise their option to purchase additional common units in full).

Our partnership agreement also provides that if our general partner is removed as our general partner under circumstances where cause does not exist and no units held by our general partner and its affiliates are voted in favor of that removal:

•: the subordination period will end and all outstanding subordinated units will immediately convert into common units on a one-for-one basis;
•: any existing arrearages in payment of the minimum quarterly distribution on the common units will be extinguished; and
•: our general partner will have the right to convert its general partner interest and its incentive distribution rights into common units or to receive cash in exchange for those interests based on the fair market value of the interests at the time.

In the event of removal of our general partner under circumstances where cause exists or withdrawal of our general partner where that withdrawal violates our partnership agreement, a successor general partner will have the option to purchase the general partner interest and incentive distribution rights of the departing general partner for a cash payment equal to the fair market value of those interests. Under all other circumstances where our general partner withdraws or is removed by the limited partners, the departing general partner will have the option to require the successor general partner to purchase the general partner interest of the departing general partner and its incentive distribution rights for their fair market value. In each case, this fair market value will be determined by agreement between the departing general partner and the successor general partner. If no agreement is reached, an independent investment banking firm or other independent expert selected by the departing general partner and the successor general partner will determine the fair market value. Or, if the departing general partner and the successor general partner cannot agree upon an expert, then an expert chosen by agreement of the experts selected by each of them will determine the fair market value.

If the option described above is not exercised by either the departing general partner or the successor general partner, the departing general partner's general partner interest and its incentive distribution rights will automatically convert into common units equal to the fair market value of those interests as determined by an investment banking firm or other independent expert selected in the manner described in the preceding paragraph.

In addition, we will be required to reimburse the departing general partner for all amounts due to it, including, without limitation, all employee-related liabilities, including severance liabilities, incurred for the termination of any employees employed by the departing general partner or its affiliates for our benefit.

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Transfer of General Partner Interest

Except for the transfer by our general partner of all, but not less than all, of its general partner interest to:

•: an affiliate of our general partner (other than an individual), or
•: another entity in connection with the merger or consolidation of our general partner with or into such other entity or the transfer by our general partner of all or substantially all of its assets to such other entity,

our general partner may not transfer all or any part of its general partner interest in our partnership to another person prior to June 30, 2018 without the approval of the holders of at least a majority of the outstanding common units, excluding common units held by our general partner and its affiliates. As a condition of this transfer, the transferee must, among other things, assume the rights and duties of our general partner, agree to be bound by the provisions of our partnership agreement, and furnish an opinion of counsel regarding limited liability and tax matters.

Our general partner and its affiliates may at any time transfer units to one or more persons, without unitholder approval, except that they may not transfer subordinated units to us.

Transfer of Ownership Interests in Our General Partner

At any time, the owners of our general partner may sell or transfer all or part of their ownership interests in our general partner to an affiliate or a third party without the approval of our unitholders.

Transfer of Incentive Distribution Rights

Our general partner, its affiliates or a subsequent holder may transfer its incentive distribution rights to an affiliate of the holder (other than an individual) or to another entity as part of the merger or consolidation of such holder with or into such entity, the sale of all of the ownership interest in such holder or the sale of all or substantially all of such holder's assets to such entity without the prior approval of the unitholders. Prior to June 30, 2018, other transfers of the incentive distribution rights will require the affirmative vote of holders of a majority of the outstanding common units excluding common units held by our general partner and its affiliates. On or after June 30, 2018, the incentive distribution rights will be freely transferable.

Change of Management Provisions

Our partnership agreement contains specific provisions that are intended to discourage a person or group from attempting to remove Rhino GP LLC as our general partner or otherwise change management. If any person or group other than our general partner and its affiliates acquires beneficial ownership of 20% or more of any class of units, that person or group loses voting rights on all of its units. This loss of voting rights does not apply to any person or group that acquires the units from our general partner or its affiliates and any transferees of that person or group approved by our general partner or to any person or group who acquires the units with the prior approval of the board of directors of our general partner.

Our partnership agreement also provides that if our general partner is removed without cause and no units held by our general partner and its affiliates are voted in favor of that removal:

•: the subordination period will end and all outstanding subordinated units will immediately convert into common units on a one-for-one basis;

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•: any existing arrearages in payment of the minimum quarterly distribution on the common units will be extinguished; and
•: our general partner will have the right to convert its general partner interest and its incentive distribution rights into common units or to receive cash in exchange for those interests.

Limited Call Right

If at any time our general partner and its affiliates own more than 90% of the then-issued and outstanding partnership securities of any class, our general partner will have the right, which it may assign in whole or in part to any of its affiliates or to us, to acquire all, but not less than all, of the remaining partnership securities of the class held by unaffiliated persons as of a record date to be selected by our general partner, on at least ten but not more than 60 days notice. If our general partner and its affiliates reduce their ownership percentage to below 50% of the outstanding common units, the ownership threshold to exercise the limited call rights will be reduced to 80%. The purchase price in the event of this purchase is the greater of:

•: the highest cash price paid by either of our general partner or any of its affiliates for any partnership securities of the class purchased within the 90 days preceding the date on which our general partner first mails notice of its election to purchase those partnership securities; and
•: the current market price as of the date three days before the date the notice is mailed.

As a result of our general partner's right to purchase outstanding partnership securities, a holder of partnership securities may have his partnership securities purchased at an undesirable time or price. The tax consequences to a unitholder of the exercise of this call right are the same as a sale by that unitholder of his common units in the market. Please read "Material Tax Consequences—Disposition of Common Units."

Meetings; Voting

Except as described below regarding a person or group owning 20% or more of any class of units then outstanding, unitholders or assignees who are record holders of units on the record date will be entitled to notice of, and to vote at, meetings of our limited partners and to act upon matters for which approvals may be solicited. Common units that are owned by an assignee who is a record holder, but who has not yet been admitted as a limited partner, will be voted by our general partner at the written direction of the record holder. Absent direction of this kind, the common units will not be voted, except that, in the case of common units held by our general partner on behalf of non-citizen assignees, our general partner will distribute the votes on those common units in the same ratios as the votes of limited partners on other units are cast.

Our general partner does not anticipate that any meeting of unitholders will be called in the foreseeable future. Any action that is required or permitted to be taken by the unitholders may be taken either at a meeting of the unitholders or without a meeting if consents in writing describing the action so taken are signed by holders of the number of units necessary to authorize or take that action at a meeting. Meetings of the unitholders may be called by our general partner or by unitholders owning at least 20% of the outstanding units of the class for which a meeting is proposed. Unitholders may vote either in person or by proxy at meetings. The holders of a majority of the outstanding units of the class or classes for which a meeting has been called, represented in person or by proxy, will constitute a quorum unless any action by the unitholders requires approval by holders of a greater percentage of the units, in which case the quorum will be the greater percentage. The unit equivalents representing the general partner interest are unit equivalents for distribution and allocation purposes, do not entitle our general partner to any vote other than its rights as general partner under our partnership agreement, will not be entitled to vote on any action required or permitted to be taken by

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the unitholders and will not count toward or be considered outstanding when calculating required votes, determining the presence of a quorum, or for similar purposes.

Each record holder of a unit has a vote according to its percentage interest in us, although additional limited partner interests having special voting rights could be issued. Please read "—Issuance of Additional Securities." However, if at any time any person or group, other than our general partner and its affiliates, or a direct or subsequently approved transferee of our general partner or its affiliates, acquires, in the aggregate, beneficial ownership of 20% or more of any class of units then outstanding, that person or group will lose voting rights on all of its units and the units may not be voted on any matter and will not be considered to be outstanding when sending notices of a meeting of unitholders, calculating required votes, determining the presence of a quorum, or for other similar purposes. Common units held in nominee or street name account will be voted by the broker or other nominee in accordance with the instruction of the beneficial owner unless the arrangement between the beneficial owner and its nominee provides otherwise. Except as our partnership agreement otherwise provides, subordinated units will vote together with common units as a single class.

Any notice, demand, request, report, or proxy material required or permitted to be given or made to record holders of common units under our partnership agreement will be delivered to the record holder by us or by the transfer agent.

Status as Limited Partner or Assignee

Except as described above under "—Limited Liability," the common units will be fully paid, and unitholders will not be required to make additional contributions.

An assignee of a common unit, after executing and delivering a transfer application, but pending its admission as a limited partner, is entitled to an interest equivalent to that of a limited partner for the right to share in allocations and distributions from us, including liquidating distributions. Our general partner will vote and exercise other powers attributable to common units owned by an assignee that has not become a limited partner at the written direction of the assignee. Please read "—Meetings; Voting." Transferees who do not execute and deliver a transfer application and certification will not be treated as assignees or as record holders of common units, and will not receive cash distributions, federal income tax allocations, or reports furnished to holders of common units. Please read "Description of the Common Units—Transfer of Common Units."

Non-Citizen Assignees; Redemption

If we are or become subject to federal, state, or local laws or regulations that, in the reasonable determination of our general partner, create a substantial risk of cancellation or forfeiture of any property in which we have an interest in because of the nationality, citizenship or other related status of any limited partner or assignee, we may redeem the units held by the limited partner or assignee at their current market price. In order to avoid any cancellation or forfeiture, our general partner may require each limited partner or assignee to furnish information about his nationality, citizenship or related status. If a limited partner or assignee fails to furnish information about his nationality, citizenship or other related status within 30 days after a request for the information or our general partner determines after receipt of the information that the limited partner or assignee is not an eligible citizen, the limited partner or assignee may be treated as a non-citizen assignee. In addition to other limitations on the rights of an assignee that is not a limited partner, a non-citizen assignee does not have the right to direct the voting of his units and may not receive distributions in kind upon our liquidation.

Furthermore, we have the right to redeem all of the common and subordinated units of any holder that our general partner concludes is not an eligible citizen or fails to furnish the information requested by our general partner. The redemption price in the event of such redemption for each unit held by

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such unitholder will be the current market price as of the date three days before the date the notice of redemption is mailed to the unitholder. The redemption price will be paid in cash or by delivery of a promissory note, as determined by our general partner. Any such promissory note will bear interest at the rate of 10% annually and be payable in three equal annual installments of principal and accrued interest, commencing one year after the redemption date.

Indemnification

Under our partnership agreement, we will indemnify the following persons in most circumstances, to the fullest extent permitted by law, from and against all losses, claims, damages, or similar events:

(1): our general partner;
(2): any departing general partner;
(3): any person who is or was an affiliate of our general partner or any departing general partner;
(4): any person who is or was an officer, director, member, partner, fiduciary or trustee of any entity described in (1), (2) or (3) above;
(5): any person who is or was serving as a director, officer, member, partner, fiduciary or trustee of another person at the request of our general partner or any departing general partner or any of their affiliates; or
(6): any person designated by our general partner.

Any indemnification under these provisions will only be out of our assets. Unless it otherwise agrees, our general partner will not be personally liable for, or have any obligation to contribute or loan funds or assets to us to enable us to effectuate, indemnification. We may purchase insurance against liabilities asserted against and expenses incurred by persons for our activities, regardless of whether we would have the power to indemnify the person against liabilities under our partnership agreement.

Reimbursement of Expenses

Our partnership agreement requires us to reimburse our general partner for all direct and indirect expenses it incurs or payments it makes on our behalf and all other expenses allocable to us or otherwise incurred by our general partner in connection with operating our business. 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 general partner is entitled to determine in good faith the expenses that are allocable to us.

Books and Reports

Our general partner is required to keep appropriate books of our business at our principal offices. The books will be maintained for both tax and financial reporting purposes on an accrual basis. For fiscal reporting purposes, we used a year end of March 31 until March 31, 2006. Effective April 1,

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2006, we changed our fiscal year end to December 31. For tax reporting purposes, we use the calendar year.

We will furnish or make available (by posting on our website or other reasonable means) to record holders of common units, within 120 days after the close of each fiscal year, an annual report containing audited financial statements and a report on those financial statements by our independent public accountants. Except for our fourth quarter, we will also furnish or make available summary financial information within 90 days after the close of each quarter.

We will furnish each record holder of a unit with information reasonably required for tax reporting purposes within 90 days after the close of each calendar year. This information is expected to be furnished in summary form so that some complex calculations normally required of partners can be avoided. Our ability to furnish this summary information to unitholders will depend on the cooperation of unitholders in supplying us with specific information. Every unitholder will receive information to assist him in determining its federal and state tax liability and filing its federal and state income tax returns, regardless of whether he supplies us with information.

Right to Inspect Our Books and Records

Our partnership agreement provides that a limited partner can, for a purpose reasonably related to its interest as a limited partner, upon reasonable demand and at its own expense, have furnished to him:

•: a current list of the name and last known address of each partner;
•: a copy of our tax returns;
•: information as to the amount of cash, and a description and statement of the agreed value of any other property or services, contributed or to be contributed by each partner and the date on which each became a partner;
•: copies of our partnership agreement, the certificate of limited partnership of the partnership, related amendments, and powers of attorney under which they have been executed;
•: information regarding the status of our business and financial condition; and
•: any other information regarding our affairs as is just and reasonable.

Our general partner may, and intends to, keep confidential from the limited partners trade secrets or other information the disclosure of which our general partner believes in good faith is not in our best interests or that we are required by law or by agreements with third parties to keep confidential.

Registration Rights

Under our partnership agreement, we have agreed to register for resale under the Securities Act of 1933 and applicable state securities laws any common units, subordinated units, or other partnership securities proposed to be sold by our general partner or any of its affiliates or their assignees if an exemption from the registration requirements is not otherwise available. These registration rights continue for two years following any withdrawal or removal of Rhino GP LLC as our general partner. We are obligated to pay all expenses incidental to the registration, excluding underwriting discounts and commissions. Please read "Units Eligible for Future Sale."

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UNITS ELIGIBLE FOR FUTURE SALE

After the sale of the common units offered by this prospectus, Rhino Energy Holdings LLC will hold an aggregate of 27,925,200 common units and 3,741,500 subordinated units. All of the subordinated units will convert into common units at the end of the subordination period and some may convert earlier. The sale of these common and subordinated units could have an adverse impact on the price of the common units or on any trading market that may develop.

The common units sold in this offering will generally be freely transferable without restriction or further registration under the Securities Act of 1933, except that any common units held by an "affiliate" of ours may not be resold publicly except in compliance with the registration requirements of the Securities Act of 1933 or under an exemption under Rule 144 or otherwise. Rule 144 permits securities acquired by an affiliate of the issuer to be sold into the market in an amount that does not exceed, during any three-month period, the greater of:

•: 1% of the total number of the securities outstanding; or
•: the average weekly reported trading volume of the common units for the four weeks prior to the sale.

Sales under Rule 144 are also subject to specific manner of sale provisions, holding period requirements, notice requirements and the availability of current public information about us. A person who is not deemed to have been an affiliate of ours at any time during the 90 days preceding a sale, and who has beneficially owned common units for at least six months, would be entitled to sell those common units under Rule 144, subject only to the current public information requirement. After beneficially owning Rule 144 restricted common units for at least one year, a person who is not deemed to have been an affiliate of ours at any time during the 90 days preceding a sale would be entitled to freely sell those common units without regard to any of the conditions of Rule 144.

Our partnership agreement provides that we may issue an unlimited number of limited partner interests of any type without a vote of the unitholders at any time. Any issuance of additional common units or other equity securities would result in a corresponding decrease in the proportionate ownership interest in us represented by, and could adversely affect the cash distributions to and market price of, common units then outstanding. Please read "The Partnership Agreement—Issuance of Additional Securities."

Under our partnership agreement, our general partner and its affiliates have the right to cause us to register under the Securities Act of 1933 and applicable state securities laws the offer and sale of any units that they hold. Subject to the terms and conditions of the partnership agreement, these registration rights allow our general partner and its affiliates or their assignees holding any units to require registration of any of these units and to include any of these units in a registration by us of other units, including units offered by us or by any unitholder. Our general partner will continue to have these registration rights for two years following its withdrawal or removal as our general partner. In connection with any registration of this kind, we will indemnify each unitholder participating in the registration and its officers, directors, and controlling persons from and against any liabilities under the Securities Act of 1933 or any applicable state securities laws arising from the registration statement or prospectus. We will bear all costs and expenses incidental to any registration, excluding any underwriting discounts and commissions. Except as described below, our general partner and its affiliates may sell their units in private transactions at any time, subject to compliance with applicable laws.

Rhino Energy Holdings LLC, the executive officers and directors of our general partner and we have agreed not to sell any common units they beneficially own for a period of 180 days from the date of this prospectus. Please read "Underwriting" for a description of these lock-up provisions.

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MATERIAL TAX CONSEQUENCES

This section is a summary of the material tax considerations that may be relevant to prospective unitholders who are individual citizens or residents of the United States and, unless otherwise noted in the following discussion, is the opinion of Vinson & Elkins L.L.P., counsel to our general partner and us, insofar as it relates to matters of U.S. federal income tax law and legal conclusions with respect to those matters. This section is based upon current provisions of the Internal Revenue Code, existing and proposed regulations and current administrative rulings and court decisions, all of which are subject to change. Later changes in these authorities may cause the tax consequences to vary substantially from the consequences described below. Unless the context otherwise requires, references in this section to "us" or "we" are references to Rhino Resource Partners, L.P. and our operating company.

The following discussion does not comment on all federal income tax matters affecting us or the unitholders. Moreover, the discussion focuses on unitholders who are individual citizens or residents of the United States and has only limited application to corporations, estates, trusts, nonresident aliens or other unitholders subject to specialized tax treatment, such as tax-exempt institutions, foreign persons, individual retirement accounts (IRAs), real estate investment trusts (REITs) or mutual funds. Accordingly, we urge each prospective unitholder to consult, and depend on, his own tax advisor in analyzing the federal, state, local and foreign tax consequences particular to him of the ownership or disposition of common units.

All statements as to matters of law and legal conclusions, but not as to factual matters, contained in this section, unless otherwise noted, are the opinion of Vinson & Elkins L.L.P. and are based on the accuracy of the representations made by us.

No ruling has been or will be requested from the IRS regarding any matter affecting us or prospective unitholders. Instead, we will rely on opinions of Vinson & Elkins L.L.P. Unlike a ruling, an opinion of counsel represents only that counsel's best legal judgment and does not bind the IRS or the courts. Accordingly, the opinions and statements made here may not be sustained by a court if contested by the IRS. Any contest of this sort with the IRS may materially and adversely impact the market for the common units and the prices at which common units trade. In addition, the costs of any contest with the IRS, principally legal, accounting and related fees, will result in a reduction in cash available for distribution to our unitholders and our general partner and thus will be borne indirectly by our unitholders and our general partner. Furthermore, the tax treatment of us, or of an investment in us, may be significantly modified by future legislative or administrative changes or court decisions. Any modifications may or may not be retroactively applied.

For the reasons described below, Vinson & Elkins L.L.P. has not rendered an opinion with respect to the following specific federal income tax issues: (1) the treatment of a unitholder whose common units are loaned to a short seller to cover a short sale of common units (please read "—Tax Consequences of Unit Ownership—Treatment of Short Sales"); (2) whether our monthly convention for allocating taxable income and losses is permitted by existing Treasury Regulations (please read "—Disposition of Common Units—Allocations Between Transferors and Transferees"); and (3) whether our method for depreciating Section 743 adjustments is sustainable in certain cases (please read "—Tax Consequences of Unit Ownership—Section 754 Election").

Partnership Status

A partnership is not a taxable entity and incurs no federal income tax liability. Instead, each partner of a partnership is required to take into account his share of items of income, gain, loss and deduction of the partnership in computing his federal income tax liability, regardless of whether cash distributions are made to him by the partnership. Distributions by a partnership to a partner are generally not taxable unless the amount of cash distributed is in excess of the partner's adjusted basis in his partnership interest.

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Section 7704 of the Internal Revenue Code provides that publicly traded partnerships will, as a general rule, be taxed as corporations. However, an exception, referred to as the "Qualifying Income Exception," exists with respect to publicly traded partnerships of which 90% or more of the gross income for every taxable year consists of "qualifying income." Qualifying income includes income and gains derived from the mining and marketing of minerals and natural resources, such as coal. Other types of qualifying income include interest (other than from a financial business), dividends, gains from the sale of real property and gains from the sale or other disposition of capital assets held for the production of income that otherwise constitutes qualifying income. We estimate that less than % of our current gross income is not qualifying income; however, this estimate could change from time to time. Based upon and subject to this estimate, the factual representations made by us and our general partner and a review of the applicable legal authorities, Vinson & Elkins L.L.P. is of the opinion that at least 90% of our current gross income constitutes qualifying income. The portion of our income that is qualifying income may change from time to time.

No ruling has been or will be sought from the IRS and the IRS has made no determination as to our status for federal income tax purposes or whether our operations generate "qualifying income" under Section 7704 of the Internal Revenue Code. Instead, we will rely on the opinion of Vinson & Elkins L.L.P. that, based upon the Internal Revenue Code, its regulations, published revenue rulings and court decisions and the representations described below, we will be classified as a partnership and our operating company will be disregarded as an entity separate from us for federal income tax purposes.

In rendering its opinion, Vinson & Elkins L.L.P. has relied on factual representations made by us and our general partner. The representations made by us and our general partner upon which Vinson & Elkins L.L.P. has relied are:

(1): Neither we nor any of our operating companies has elected or will elect to be treated as a corporation; and
(2): For each taxable year, more than 90% of our gross income has been and will be income that Vinson & Elkins L.L.P. has opined or will opine is "qualifying income" within the meaning of Section 7704(d) of the Internal Revenue Code.

If we fail to meet the Qualifying Income Exception, other than a failure that is determined by the IRS to be inadvertent and that is cured within a reasonable time after discovery (in which case the IRS may also require us to make adjustments with respect to our unitholders or pay other amounts), we will be treated as if we had transferred all of our assets, subject to liabilities, to a newly formed corporation, on the first day of the year in which we fail to meet the Qualifying Income Exception, in return for stock in that corporation, and then distributed that stock to the unitholders in liquidation of their interests in us. This deemed contribution and liquidation should be tax-free to unitholders and us so long as we, at that time, do not have liabilities in excess of the tax basis of our assets. Thereafter, we would be treated as a corporation for federal income tax purposes.

If we were treated as an association taxable as a corporation in any taxable year, either as a result of a failure to meet the Qualifying Income Exception or otherwise, our items of income, gain, loss and deduction would be reflected only on our tax return rather than being passed through to the unitholders, and our net income would be taxed to us at corporate rates. In addition, any distribution made to a unitholder would be treated as either taxable dividend income, to the extent of our current or accumulated earnings and profits, or, in the absence of earnings and profits, a nontaxable return of capital, to the extent of the unitholder's tax basis in his common units, or taxable capital gain, after the unitholder's tax basis in his common units is reduced to zero. Accordingly, taxation as a corporation would result in a material reduction in a unitholder's cash flow and after-tax return and thus would likely result in a substantial reduction of the value of the units.

The discussion below is based on Vinson & Elkins L.L.P.'s opinion that we will be classified as a partnership for federal income tax purposes.

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Limited Partner Status

Unitholders who have become limited partners of Rhino Resource Partners, L.P. will be treated as partners of Rhino Resource Partners, L.P. for federal income tax purposes. Also:

•: assignees who have executed and delivered transfer applications, and are awaiting admission as limited partners, and
•: unitholders whose common units are held in street name or by a nominee and who have the right to direct the nominee in the exercise of all substantive rights attendant to the ownership of their common units will be treated as partners of Rhino Resource Partners, L.P. for federal income tax purposes.

As there is no direct or indirect controlling authority addressing assignees of common units who are entitled to execute and deliver transfer applications and thereby become entitled to direct the exercise of attendant rights, but who fail to execute and deliver transfer applications, Vinson & Elkins L.L.P.'s opinion does not extend to these persons. Furthermore, a purchaser or other transferee of common units who does not execute and deliver a transfer application may not receive some federal income tax information or reports furnished to record holders of common units unless the common units are held in a nominee or street name account and the nominee or broker has executed and delivered a transfer application for those common units.

A beneficial owner of common units whose units have been transferred to a short seller to complete a short sale would appear to lose his status as a partner with respect to those units for federal income tax purposes. Please read "—Tax Consequences of Unit Ownership—Treatment of Short Sales."

Income, gain, deductions or losses would not appear to be reportable by a unitholder who is not a partner for federal income tax purposes, and any cash distributions received by a unitholder who is not a partner for federal income tax purposes would therefore appear to be fully taxable as ordinary income. These holders are urged to consult their own tax advisors with respect to their tax consequences of holding common units in Rhino Resource Partners, L.P.

Tax Consequences of Unit Ownership

Flow-Through of Taxable Income

We will not pay any federal income tax. Instead, each unitholder will be required to report on his income tax return his share of our income, gains, losses and deductions without regard to whether we make cash distributions to him. Consequently, we may allocate income to a unitholder even if he has not received a cash distribution. Each unitholder will be required to include in income his allocable share of our income, gains, losses and deductions for our taxable year ending with or within his taxable year. Our taxable year ends on December 31.

Treatment of Distributions

Distributions by us to a unitholder generally will not be taxable to the unitholder for federal income tax purposes, except to the extent the amount of any such cash distribution exceeds his tax basis in his common units immediately before the distribution. Our cash distributions in excess of a unitholder's tax basis generally will be considered to be gain from the sale or exchange of the common units, taxable in accordance with the rules described under "—Disposition of Common Units" below. Any reduction in a unitholder's share of our liabilities for which no partner, including our general partner, bears the economic risk of loss, known as "nonrecourse liabilities," will be treated as a distribution of cash to that unitholder. To the extent our distributions cause a unitholder's "at risk" amount to be less than zero at the end of any taxable year, he must recapture any losses deducted in previous years. Please read "—Limitations on Deductibility of Losses."

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A decrease in a unitholder's percentage interest in us because of our issuance of additional common units will decrease his share of our nonrecourse liabilities, and thus will result in a corresponding deemed distribution of cash. This deemed distribution may constitute a non-pro rata distribution. A non-pro rata distribution of money or property may result in ordinary income to a unitholder, regardless of his tax basis in his common units, if the distribution reduces the unitholder's share of our "unrealized receivables," which includes depreciation and depletion recapture, and/or substantially appreciated "inventory items," both as defined in the Internal Revenue Code, and collectively, "Section 751 Assets." To that extent, he will be treated as having been distributed his proportionate share of the Section 751 Assets and having exchanged those assets with us in return for the non-pro rata portion of the actual distribution made to him. This latter deemed exchange will generally result in the unitholder's realization of ordinary income, which will equal the excess of (1) the non-pro rata portion of that distribution over (2) the unitholder's tax basis (generally zero) for the share of Section 751 Assets deemed relinquished in the exchange.

Ratio of Taxable Income to Distributions

We estimate that a purchaser of common units in this offering who owns those common units from the date of closing of this offering through the record date for distributions for the period ending December 31, 2011, will be allocated, on a cumulative basis, an amount of federal taxable income for that period that will be % or less of the cash distributed with respect to that period. We anticipate that after the period ending December 31, 2011, the ratio of allocable taxable income to cash distributions to the unitholders will increase. These estimates are based upon the assumption that gross income from operations will approximate the amount required to make the minimum quarterly distribution on all units and other assumptions with respect to capital expenditures, cash flow, net working capital and anticipated cash distributions. These estimates and assumptions are subject to, among other things, numerous business, economic, regulatory, competitive and political uncertainties beyond our control. Further, the estimates are based on current tax law and tax reporting positions that we will adopt and with which the IRS could disagree. Accordingly, we cannot assure you that these estimates will prove to be correct. The actual percentage of distributions that will constitute taxable income could be higher or lower, and any differences could be material and could materially affect the value of the common units.

Basis of Common Units

A unitholder's initial tax basis for his common units will be the amount he paid for the common units plus his share of our nonrecourse liabilities. That basis will be increased by his share of our income and by any increases in his share of our nonrecourse liabilities. That basis will be decreased, but not below zero, by distributions from us, by the unitholder's share of our losses, by any decreases in his share of our nonrecourse liabilities and by his share of our expenditures that are not deductible in computing taxable income and are not required to be capitalized. A unitholder will have no share of our debt that is recourse to our general partner, but will have a share, generally based on his share of profits, of our nonrecourse liabilities. Please read "—Disposition of Common Units—Recognition of Gain or Loss."

Limitations on Deductibility of Losses

The deduction by a unitholder of his share of our losses will be limited to the tax basis in his units and, in the case of an individual unitholder or a corporate unitholder, if more than 50% of the value of the corporate unitholder's stock is owned directly or indirectly by five or fewer individuals or some tax-exempt organizations, to the amount for which the unitholder is considered to be "at risk" with respect to our activities, if that is less than his tax basis. A unitholder must recapture losses deducted in previous years to the extent that distributions cause his at risk amount to be less than zero at the end of any taxable year. Losses disallowed to a unitholder or recaptured as a result of these limitations will

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carry forward and will be allowable as a deduction to the extent that his at-risk amount is subsequently increased, so long as such losses do not exceed such common unitholders' tax basis in his common units. Upon the taxable disposition of a unit, any gain recognized by a unitholder can be offset by losses that were previously suspended by the at risk limitation but may not be offset by losses suspended by the basis limitation. Any excess loss above that gain previously suspended by the at risk or basis limitations is no longer utilizable.

In general, a unitholder will be at risk to the extent of the tax basis of his units, excluding any portion of that basis attributable to his share of our nonrecourse liabilities, reduced by (1) any portion of that basis representing amounts otherwise protected against loss because of a guarantee, stop loss agreement or other similar arrangement and (2) any amount of money he borrows to acquire or hold his units, if the lender of those borrowed funds owns an interest in us, is related to another unitholder who has an interest in us or can look only to the units for repayment. A unitholder's at-risk amount will increase or decrease as the tax basis of the unitholder's units increases or decreases, other than tax basis increases or decreases attributable to increases or decreases in his share of our nonrecourse liabilities.

In addition to the basis and at-risk limitations on the deductibility of losses, the passive loss limitations generally provide that individuals, estates, trusts and some closely-held corporations and personal service corporations can deduct losses from passive activities, which are generally corporate or partnership activities in which the taxpayer does not materially participate, only to the extent of the taxpayer's income from those passive activities. The passive loss limitations are applied separately with respect to each publicly traded partnership. Consequently, any passive losses we generate will only be available to offset our passive income generated in the future and will not be available to offset income from other passive activities or investments, including our investments or investments in other publicly traded partnerships, or salary or active business income. Passive losses that are not deductible because they exceed a unitholder's share of income we generate may be deducted in full when he disposes of his entire investment in us in a fully taxable transaction with an unrelated party. The passive activity loss rules are applied after other applicable limitations on deductions, including the at risk rules and the basis limitation.

A unitholder's share of our net income may be offset by any of our suspended passive losses, but it may not be offset by any other current or carryover losses from other passive activities, including those attributable to other publicly traded partnerships.

Limitations on Interest Deductions

The deductibility of a non-corporate taxpayer's "investment interest expense" is generally limited to the amount of that taxpayer's "net investment income." Investment interest expense includes:

•: interest on indebtedness properly allocable to property held for investment;
•: our interest expense attributed to portfolio income; and
•: the portion of interest expense incurred to purchase or carry an interest in a passive activity to the extent attributable to portfolio income.

The computation of a unitholder's investment interest expense will take into account interest on any margin account borrowing or other loan incurred to purchase or carry a unit. Net investment income includes gross income from property held for investment and amounts treated as portfolio income under the passive loss rules, less deductible expenses, other than interest, directly connected with the production of investment income, but generally does not include gains attributable to the disposition of property held for investment. The IRS has indicated that net passive income earned by a publicly traded partnership will be treated as investment income to its unitholders. In addition, the unitholder's share of our portfolio income will be treated as investment income.

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Entity-Level Collections

If we are required or elect under applicable law to pay any federal, state, local or foreign income tax on behalf of any unitholder or our general partner or any former unitholder, we are authorized to pay those taxes from our funds. That payment, if made, will be treated as a distribution of cash to the unitholder on whose behalf the payment was made. If the payment is made on behalf of a person whose identity cannot be determined, we are authorized to treat the payment as a distribution to all current unitholders. We are authorized to amend our partnership agreement in the manner necessary to maintain uniformity of intrinsic tax characteristics of units and to adjust later distributions, so that after giving effect to these distributions, the priority and characterization of distributions otherwise applicable under our partnership agreement is maintained as nearly as is practicable. Payments by us as described above could give rise to an overpayment of tax on behalf of an individual unitholder in which event the unitholder would be required to file a claim in order to obtain a credit or refund.

Allocation of Income, Gain, Loss and Deduction

In general, if we have a net profit, our items of income, gain, loss and deduction will be allocated among our general partner and the unitholders in accordance with their percentage interests in us. At any time that distributions are made to the common units in excess of distributions to the subordinated units, or incentive distributions are made to our general partner, gross income will be allocated to the recipients to the extent of these distributions. If we have a net loss for the entire year, that loss will be allocated first to our general partner and the unitholders in accordance with their percentage interests in us to the extent of their positive capital accounts and, second, to our general partner.

Specified items of our income, gain, loss and deduction will be allocated to account for the difference between the tax basis and fair market value of property contributed to us by our general partner and its affiliates, referred to in this discussion as the "Contributed Property." The effect of these allocations, referred to as "Section 704(c) Allocations," to a unitholder purchasing common units from us in this offering will be essentially the same as if the tax bases of our assets were equal to their fair market value at the time of this offering. In the event we issue additional common units or engage in certain other transactions in the future "Reverse Section 704(c) Allocations," similar to the Section 704(c) Allocations described above, will be made to holders of partnership interests immediately prior to such other transactions to account for the difference between the "book" basis for purposes of maintaining capital accounts and the fair market value of all property held by us at the time of the future transaction. In addition, items of recapture income will be allocated to the extent possible to the unitholder who was allocated the deduction giving rise to the treatment of that gain as recapture income in order to minimize the recognition of ordinary income by some unitholders. Finally, although we do not expect that our operations will result in the creation of negative capital accounts, if negative capital accounts nevertheless result, items of our income and gain will be allocated in an amount and manner sufficient to eliminate the negative balance as quickly as possible.

An allocation of items of our income, gain, loss or deduction, other than an allocation required by the Internal Revenue Code to eliminate the difference between a partner's "book" capital account, credited with the fair market value of Contributed Property, and "tax" capital account, credited with the tax basis of Contributed Property, referred to in this discussion as the "Book-Tax Disparity," will generally be given effect for federal income tax purposes in determining a partner's share of an item of income, gain, loss or deduction only if the allocation has substantial economic effect. In any other case, a partner's share of an item will be determined on the basis of his interest in us, which will be determined by taking into account all the facts and circumstances, including:

•: his relative contributions to us;
•: the interests of all the partners in profits and losses;
•: the interest of all the partners in cash flow; and

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•: the rights of all the partners to distributions of capital upon liquidation.

Vinson & Elkins L.L.P. is of the opinion that, with the exception of the issues described in "—Tax Consequences of Unit Ownership—Section 754 Election" and "—Disposition of Common Units—Allocations Between Transferors and Transferees," allocations under our partnership agreement will be given effect for federal income tax purposes in determining a partner's share of an item of income, gain, loss or deduction.

Treatment of Short Sales

•: any of our income, gain, loss or deduction with respect to those units would not be reportable by the unitholder;
•: any cash distributions received by the unitholder as to those units would be fully taxable; and
•: all of these distributions would appear to be ordinary income.

Vinson & Elkins L.L.P. 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 modify any applicable brokerage account agreements to prohibit their brokers from loaning their units. The IRS has announced that it is actively studying issues relating to the tax treatment of short sales of partnership interests. Please also read "—Disposition of Common Units—Recognition of Gain or Loss."

Alternative Minimum Tax

Each unitholder will be required to take into account his distributive share of any items of our income, gain, loss or deduction for purposes of the alternative minimum tax. The current minimum tax rate for noncorporate taxpayers is 26% on the first $175,000 of alternative minimum taxable income in excess of the exemption amount and 28% on any additional alternative minimum taxable income. Prospective unitholders are urged to consult with their tax advisors as to the impact of an investment in units on their liability for the alternative minimum tax.

Tax Rates

In general, the highest effective U.S. federal income tax rate for individuals is currently 35%, and the maximum U.S. federal income tax rate for net capital gains of an individual where the asset disposed of was a capital asset held for more than twelve months at the time of disposition, is scheduled to remain at 15% for the years 2008 through 2010 and then increase to 20% beginning January 1, 2011.

Section 754 Election

We will make the election permitted by Section 754 of the Internal Revenue Code. That election is irrevocable without the consent of the IRS. The election will generally permit us to adjust a common unit purchaser's tax basis in our assets ("inside basis") under Section 743(b) of the Internal Revenue Code to reflect his purchase price. This election does not apply to a person who purchases common units directly from us. The Section 743(b) adjustment belongs to the purchaser and not to other unitholders. For purposes of this discussion, a unitholder's inside basis in our assets will be considered to have two components: (1) his share of our tax basis in our assets ("common basis") and (2) his Section 743(b) adjustment to that basis.

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Where the remedial allocation method is adopted (which we will generally adopt as to our properties), the Treasury Regulations under Section 743 of the Internal Revenue Code require a portion of the Section 743(b) adjustment that is attributable to recovery property under Section 168 of the Internal Revenue Code whose book basis is in excess of its tax basis to be depreciated over the remaining cost recovery period for the property's unamortized book-tax disparity. Under Treasury Regulation Section 1.167(c)-1(a)(6), a Section 743(b) adjustment attributable to property subject to depreciation under Section 167 of the Internal Revenue Code, rather than cost recovery deductions under Section 168, is generally required to be depreciated using either the straight-line method or the 150% declining balance method. Under our partnership agreement, our general partner is authorized to take a position to preserve the uniformity of units even if that position is not consistent with these and any other Treasury Regulations. Please read "—Uniformity of Units."

Although Vinson & Elkins L.L.P. is unable to opine as to the validity of this approach because there is no direct or indirect controlling authority on this issue, we intend to depreciate the portion of a Section 743(b) adjustment attributable to unrealized appreciation in the value of Contributed Property, to the extent of any unamortized Book-Tax Disparity, using a rate of depreciation or amortization derived from the depreciation or amortization method and useful life applied to the property's unamortized book-tax disparity, or treat that portion as non-amortizable to the extent attributable to property which is not amortizable. This method is consistent with the methods employed by other publicly traded partnerships but is arguably inconsistent with Treasury Regulation Section 1.167(c)-1(a)(6), which is not expected to directly apply to a material portion of our assets. To the extent this Section 743(b) adjustment is attributable to appreciation in value in excess of the unamortized Book-Tax Disparity, we will apply the rules described in the Treasury Regulations and legislative history. If we determine that this position cannot reasonably be taken, we may take a depreciation or amortization position under which all purchasers acquiring units in the same month would receive depreciation or amortization, whether attributable to common basis or a Section 743(b) adjustment, based upon the same applicable rate as if they had purchased a direct interest in our assets. This kind of aggregate approach may result in lower annual depreciation or amortization deductions than would otherwise be allowable to some unitholders. Please read "—Uniformity of Units." A unitholder's tax basis for his common units is reduced by his share of our deductions (whether or not such deductions were claimed on an individual's income tax return) so that any position we take that understates deductions will overstate the common unitholder's basis in his common units, which may cause the unitholder to understate gain or overstate loss on any sale of such units. Please read "—Disposition of Common Units—Recognition of Gain or Loss." The IRS may challenge our position with respect to depreciating or amortizing the Section 743(b) adjustment we take to preserve the uniformity of the units. If such a challenge were sustained, the gain from the sale of units might be increased without the benefit of additional deductions.

A Section 754 election is advantageous if the transferee's tax basis in his units is higher than the units' share of the aggregate tax basis of our assets immediately prior to the transfer. In that case, as a result of the election, the transferee would have, among other items, a greater amount of depreciation and depletion deductions and his share of any gain or loss on a sale of our assets would be less. Conversely, a Section 754 election is disadvantageous if the transferee's tax basis in his units is lower than those units' share of the aggregate tax basis of our assets immediately prior to the transfer. Thus, the fair market value of the units may be affected either favorably or unfavorably by the election. A basis adjustment is required regardless of whether a Section 754 election is made in the case of a transfer of an interest in us if we have a substantial built-in loss immediately after the transfer, or if we distribute property and have a substantial basis reduction. Generally, a built-in loss or a basis reduction is substantial if it exceeds $250,000.

The calculations involved in the Section 754 election are complex and will be made on the basis of assumptions as to the value of our assets and other matters. For example, the allocation of the Section 743(b) adjustment among our assets must be made in accordance with the Internal Revenue

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Code. The IRS could seek to reallocate some or all of any Section 743(b) adjustment allocated by us to our tangible assets to goodwill instead. Goodwill, as an intangible asset, is generally non-amortizable or amortizable over a longer period of time or under a less accelerated method than our tangible assets. We cannot assure you that the determinations we make will not be successfully challenged by the IRS and that the deductions resulting from them will not be reduced or disallowed altogether. Should the IRS require a different basis adjustment to be made, and should, in our opinion, the expense of compliance exceed the benefit of the election, we may seek permission from the IRS to revoke our Section 754 election. If permission is granted, a subsequent purchaser of units may be allocated more income than he would have been allocated had the election not been revoked.

Tax Treatment of Operations

Accounting Method and Taxable Year

We use the year ending December 31 as our taxable year and the accrual method of accounting for federal income tax purposes. Each unitholder will be required to include in income his share of our income, gain, loss and deduction for our taxable year ending within or with his taxable year. In addition, a unitholder who has a taxable year ending on a date other than December 31 and who disposes of all of his units following the close of our taxable year but before the close of his taxable year must include his share of our income, gain, loss and deduction in income for his taxable year, with the result that he will be required to include in income for his taxable year his share of more than one year of our income, gain, loss and deduction. Please read "—Disposition of Common Units—Allocations Between Transferors and Transferees."

Initial Tax Basis, Depreciation and Amortization

The tax basis of our assets will be used for purposes of computing depreciation and cost recovery deductions and, ultimately, gain or loss on the disposition of these assets. The federal income tax burden associated with the difference between the fair market value of our assets and their tax basis immediately prior to this offering will be borne by our general partner. Please read "—Tax Consequences of Unit Ownership—Allocation of Income, Gain, Loss and Deduction."

To the extent allowable, we may elect to use the depreciation and cost recovery methods that will result in the largest deductions being taken in the early years after assets are placed in service. Property we subsequently acquire or construct may be depreciated using accelerated methods permitted by the Internal Revenue Code.

If we dispose of depreciable property by sale, foreclosure or otherwise, all or a portion of any gain, determined by reference to the amount of depreciation previously deducted and the nature of the property, may be subject to the recapture rules and taxed as ordinary income rather than capital gain. Similarly, a unitholder who has taken cost recovery or depreciation deductions with respect to property we own will likely be required to recapture some or all of those deductions as ordinary income upon a sale of his interest in us. Please read "—Tax Consequences of Unit Ownership—Allocation of Income, Gain, Loss and Deduction" and "—Disposition of Common Units—Recognition of Gain or Loss."

The costs incurred in selling our units (called "syndication expenses") must be capitalized and cannot be deducted currently, ratably or upon our termination. There are uncertainties regarding the classification of costs as organization expenses, which may be amortized by us, and as syndication expenses, which may not be amortized by us. The underwriting discounts and commissions we incur will be treated as syndication expenses.

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Coal Depletion

In general, we are entitled to depletion deductions with respect to coal mined from the underlying mineral property. We generally are entitled to the greater of cost depletion limited to the basis of the property or percentage depletion. The percentage depletion rate for coal is 10%.

Depletion deductions we claim generally will reduce the tax basis of the underlying mineral property. Depletion deductions can, however, exceed the total tax basis of the mineral property. The excess of our percentage depletion deductions over the adjusted tax basis of the property at the end of the taxable year is subject to tax preference treatment in computing the alternative minimum tax. Please read "—Tax Consequences of Unit Ownership—Alternative Minimum Tax." Upon the disposition of the mineral property, a portion of the gain, if any, equal to the lesser of the deductions for depletion which reduce the adjusted tax basis of the mineral property plus deductible development and mining exploration expenses, or the amount of gain recognized upon the disposition, will be treated as ordinary income to us. In addition, a corporate unitholder's allocable share of the amount allowable as a percentage depletion deduction for any property will be reduced by 20% of the excess, if any, of that partner's allocable share of the amount of the percentage depletion deductions for the taxable year over the adjusted tax basis of the mineral property as of the close of the taxable year.

Mining Exploration and Development Expenditures

We will elect to currently deduct mining exploration expenditures that we pay or incur to determine the existence, location, extent or quality of coal deposits prior to the time the existence of coal in commercially marketable quantities has been disclosed.

Amounts we deduct for mine exploration expenditures must be recaptured and included in our taxable income at the time a mine reaches the production stage, unless we elect to reduce future depletion deductions by the amount of the recapture. A mine reaches the producing stage when the major part of the coal production is obtained from working mines other than those opened for the purpose of development or the principal activity of the mine is the production of developed coal rather than the development of additional coal for mining. This recapture is accomplished through the disallowance of both cost and percentage depletion deductions on the particular mine reaching the producing stage. This disallowance of depletion deductions continues until the amount of adjusted exploration expenditures with respect to the mine have been fully recaptured. This recapture is not applied to the full amount of the previously deducted exploration expenditures. Instead, these expenditures are reduced by the amount of percentage depletion, if any, that was lost as a result of deducting these exploration expenditures.

We will also generally deduct currently mine development expenditures incurred in making coal accessible for extraction, after the exploration process has disclosed the existence of coal in commercially marketable quantities. To increase the allowable percentage depletion deduction for a mine or mines, we may however, elect to defer mine development expenses and deduct them on a ratable basis as the coal benefited by the expenses is sold. This election can be made on a mine-by-mine and year-by-year basis.

Mine exploration and development expenditures are subject to recapture as ordinary income to the extent of any gain upon a sale or other disposition of our property or of your common units. See "—Disposition of Common Units." Corporate unitholders are subject to an additional rule that requires them to capitalize a portion of their otherwise deductible mine exploration and development expenditures. Corporate unitholders, other than some S corporations, are required to reduce their otherwise deductible exploration expenditures by 30%. These capitalized mine exploration and development expenditures must be amortized over a 60-month period, beginning in the month paid or incurred, using a straight-line method and may not be treated as part of the basis of the property for purposes of computing depletion.

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When computing the alternative minimum tax, mine exploration and development expenditures are capitalized and deducted over a ten year period. Unitholders may avoid this alternative minimum tax adjustment of their mine exploration and development expenditures by electing to capitalize all or part of the expenditures and deducting them over ten years for regular income tax purposes. You may select the specific amount of these expenditures for which you wish to make this election.

Sales of Coal Reserves

If any coal reserves are sold or otherwise disposed of in a taxable transaction, we will recognize gain or loss measured by the difference between the amount realized (including the amount of any indebtedness assumed by the purchaser upon such disposition or to which such property is subject) and the adjusted tax basis of the property sold. Generally, the character of any gain or loss recognized upon that disposition will depend upon whether our coal reserves or the mined coal sold are held by us:

•: for sale to customers in the ordinary course of business (i.e., we are a "dealer" with respect to that property),
•: for use in a trade or business within the meaning of Section 1231 of the Internal Revenue Code or
•: as a capital asset within the meaning of Section 1221 of the Internal Revenue Code.

In determining dealer status with respect to coal reserves and other types of real estate, the courts have identified a number of factors for distinguishing between a particular property held for sale in the ordinary course of business and one held for investment. Any determination must be based on all the facts and circumstances surrounding the particular property and sale in question.

We intend to hold our coal reserves for use in a trade or business and achieving long-term capital appreciation. Although our general partner may consider strategic sales of coal reserves consistent with achieving long-term capital appreciation, our general partner does not anticipate frequent sales of coal reserves. Thus, our general partner does not believe we will be viewed as a dealer. In light of the factual nature of this question, however, there is no assurance that our purposes for holding our properties will not change and that our future activities will not cause us to be a "dealer" in coal reserves.

If we are not a dealer with respect to our coal reserves and we have held the disposed property for more than a one-year period primarily for use in our trade or business, the character of any gain or loss realized from a disposition of the property will be determined under Section 1231 of the Internal Revenue Code. If we have not held the property for more than one year at the time of the sale, gain or loss from the sale will be taxable as ordinary income.

A unitholder's distributive share of any Section 1231 gain or loss generated by us will be aggregated with any other gains and losses realized by that unitholder from the disposition of property used in the trade or business, as defined in Section 1231(b) of the Internal Revenue Code, and from the involuntary conversion of such properties and of capital assets held in connection with a trade or business or a transaction entered into for profit for the requisite holding period. If a net gain results, all such gains and losses will be long-term capital gains and losses; if a net loss results, all such gains and losses will be ordinary income and losses. Net Section 1231 gains will be treated as ordinary income to the extent of prior net Section 1231 losses of the taxpayer or predecessor taxpayer for the five most recent prior taxable years to the extent such losses have not previously been offset against Section 1231 gains. Losses are deemed recaptured in the chronological order in which they arose.

If we are not a dealer with respect to our coal reserves and that property is not used in a trade or business, the property will be a "capital asset" within the meaning of Section 1221 of the Internal Revenue Code. Gain or loss recognized from the disposition of that property will be taxable as capital

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gain or loss, and the character of such capital gain or loss as long-term or short-term will be based upon our holding period of such property at the time of its sale. The requisite holding period for long-term capital gain is more than one year.

Upon a disposition of coal reserves, a portion of the gain, if any, equal to the lesser of (1) the depletion deductions that reduced the tax basis of the disposed mineral property plus deductible development and mining exploration expenses or (2) the amount of gain recognized on the disposition, will be treated as ordinary income to us.

Deduction for U.S. Production Activities

Subject to the limitations on the deductibility of losses discussed above and the limitation discussed below, unitholders will be entitled to a deduction, herein referred to as the Section 199 deduction, equal to a specified percentage of our qualified production activities income that is allocated to such common unitholder, but not to exceed 50% of such unitholder's IRS Form W-2 wages for the taxable year allocable to domestic production gross receipts. The percentages are 6% for qualified production activities income generated in the years 2008 and 2009; and 9% thereafter.

Qualified production activities income is generally equal to gross receipts from domestic production activities reduced by cost of goods sold allocable to those receipts, other expenses directly associated with those receipts, and a share of other deductions, expenses and losses that are not directly allocable to those receipts or another class of income. The products produced must be manufactured, produced, grown or extracted in whole or in significant part by the taxpayer in the United States.

For a partnership, the Section 199 deduction is determined at the partner level. To determine his Section 199 deduction, each unitholder will aggregate his share of the qualified production activities income allocated to him from us with the unitholder's qualified production activities income from other sources. Each unitholder must take into account his distributive share of the expenses allocated to him from our qualified production activities regardless of whether we otherwise have taxable income. However, our expenses that otherwise would be taken into account for purposes of computing the Section 199 deduction are only taken into account if and to the extent the unitholder's share of losses and deductions from all of our activities is not disallowed by the basis rules, the at risk rules or the passive activity loss rules. Please read "—Tax Consequences of Unit Ownership—Limitations on Deductibility of Losses."

The amount of a common unitholder's Section 199 deduction for each year is limited to 50% of the IRS Form W-2 wages actually or deemed paid by the common unitholder during the calendar year that are deducted in arriving at qualified production activities income. Each common unitholder is treated as having been allocated IRS Form W-2 wages from us equal to the common unitholder's allocable share of our wages that are deducted in arriving at qualified production activities income for that taxable year. It is not anticipated that we or our subsidiaries will pay material wages that will be allocated to our unitholders, and thus a unitholder's ability to claim the Section 199 deduction may be limited.

This discussion of the Section 199 deduction does not purport to be a complete analysis of the complex legislation and Treasury authority relating to the calculation of domestic production gross receipts, qualified production activities income, or IRS Form W-2 Wages, or how such items are allocated by us to unitholders. Further, because the Section 199 deduction is required to be computed separately by each unitholder, no assurance can be given, and counsel is unable to express any opinion, as to the availability or extent of the Section 199 deduction to the unitholders. Each prospective unitholder is encouraged to consult his tax advisor to determine whether the Section 199 deduction would be available to him.

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Valuation and Tax Basis of Our Properties

The federal income tax consequences of the ownership and disposition of units will depend in part on our estimates of the relative fair market values, and the initial tax bases, of our assets. Although we may from time to time consult with professional appraisers regarding valuation matters, we will make many of the relative fair market value estimates ourselves. These estimates and determinations of basis are subject to challenge and will not be binding on the IRS or the courts. If the estimates of fair market value or basis are later found to be incorrect, the character and amount of items of income, gain, loss or deductions previously reported by unitholders might change, and unitholders might be required to adjust their tax liability for prior years and incur interest and penalties with respect to those adjustments.

Disposition of Common Units

Recognition of Gain or Loss

Gain or loss will be recognized on a sale of units equal to the difference between the amount realized and the unitholder's tax basis for the units sold. A unitholder's amount realized will be measured by the sum of the cash or the fair market value of other property received by him plus his share of our nonrecourse liabilities. Because the amount realized includes a unitholder's share of our nonrecourse liabilities, the gain recognized on the sale of units could result in a tax liability in excess of any cash received from the sale.

Prior distributions from us in excess of cumulative net taxable income for a common unit that decreased a unitholder's tax basis in that common unit will, in effect, become taxable income if the common unit is sold at a price greater than the unitholder's tax basis in that common unit, even if the price received is less than his original cost.

Except as noted below, gain or loss recognized by a unitholder, other than a "dealer" in units, on the sale or exchange of a unit held for more than one year will generally be taxable as long-term capital gain or loss. Capital gain recognized by an individual on the sale of units held more than twelve months will generally be taxed at a maximum rate of 15% through December 31, 2010. However, a portion of this gain or loss, which will likely be substantial, will be separately computed and taxed as ordinary income or loss under Section 751 of the Internal Revenue Code to the extent attributable to assets giving rise to depreciation recapture or other "unrealized receivables" or to "inventory items" we own. The term "unrealized receivables" includes potential recapture items, including depreciation and depletion recapture. Ordinary income attributable to unrealized receivables, inventory items and depreciation recapture may exceed net taxable gain realized upon the sale of a unit and may be recognized even if there is a net taxable loss realized on the sale of a unit. Thus, a unitholder may recognize both ordinary income and a capital loss upon a sale of units. Net capital losses may offset capital gains and no more than $3,000 of ordinary income each year, in the case of individuals, and may only be used to offset capital gains in the case of corporations.

The IRS has ruled that a partner who acquires interests in a partnership in separate transactions must combine those interests and maintain a single adjusted tax basis for all those interests. Upon a sale or other disposition of less than all of those interests, a portion of that tax basis must be allocated to the interests sold using an "equitable apportionment" method, which generally means that the tax basis allocated to the interest sold equals an amount that bears the same relation to the partner's tax basis in his entire interest in the partnership as the value of the interest sold bears to the value of the partner's entire interest in the partnership. Treasury Regulations under Section 1223 of the Internal Revenue Code allow a selling unitholder who can identify common units transferred with an ascertainable holding period to elect to use the actual holding period of the common units transferred. Thus, according to the ruling, a common unitholder will be unable to select high or low basis common units to sell as would be the case with corporate stock, but, according to the regulations, may designate

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specific common units sold for purposes of determining the holding period of units transferred. A unitholder electing to use the actual holding period of common units transferred must consistently use that identification method for all subsequent sales or exchanges of common units. A unitholder considering the purchase of additional units or a sale of common units purchased in separate transactions is urged to consult his tax advisor as to the possible consequences of this ruling and application of the Treasury Regulations.

Specific provisions of the Internal Revenue Code affect the taxation of some financial products and securities, including partnership interests, by treating a taxpayer as having sold an "appreciated" partnership interest, one in which gain would be recognized if it were sold, assigned or terminated at its fair market value, if the taxpayer or related persons enter(s) into:

•: a short sale;
•: an offsetting notional principal contract; or
•: a futures or forward contract with respect to the partnership interest or substantially identical property.

Moreover, if a taxpayer has previously entered into a short sale, an offsetting notional principal contract or a futures or forward contract with respect to the partnership interest, the taxpayer will be treated as having sold that position if the taxpayer or a related person then acquires the partnership interest or substantially identical property. The Secretary of the Treasury is also authorized to issue regulations that treat a taxpayer that enters into transactions or positions that have substantially the same effect as the preceding transactions as having constructively sold the financial position.

Allocations Between Transferors and Transferees

In general, our taxable income or loss will be determined annually, will be prorated on a monthly basis and will be subsequently apportioned among the unitholders in proportion to the number of units owned by each of them as of the opening of the applicable exchange on the first business day of the month, which we refer to in this prospectus as the "Allocation Date." However, gain or loss realized on a sale or other disposition of our assets other than in the ordinary course of business will be allocated among the unitholders on the Allocation Date in the month in which that gain or loss is recognized. As a result, a unitholder transferring units may be allocated income, gain, loss and deduction realized after the date of transfer.

Although simplifying conventions are contemplated by the Internal Revenue Code and most publicly traded partnerships use similar simplifying conventions, the use of this method may not be permitted under existing Treasury Regulations. Accordingly, Vinson & Elkins L.L.P. is unable to opine on the validity of this method of allocating income and deductions between transferor and transferee unitholders. If this method is not allowed under the Treasury Regulations, or only applies to transfers of less than all of the unitholder's interest, our taxable income or losses might be reallocated among the transferor and transferee unitholders. We are authorized to revise our method of allocation between unitholders, as well as unitholders whose interests vary during a taxable year, to conform to a method permitted under future Treasury Regulations.

A unitholder who owns units at any time during a quarter and who disposes of them prior to the record date set for a cash distribution for that quarter will be allocated items of our income, gain, loss and deductions attributable to that quarter but will not be entitled to receive that cash distribution.

Notification Requirements

A unitholder who sells any of his units generally is required to notify us in writing of that sale within 30 days after the sale (or, if earlier, January 15 of the year following the sale). A purchaser of

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units who purchases units from another unitholder also generally is required to notify us in writing of that purchase within 30 days after the purchase. Upon receiving such notifications, we are required to notify the IRS of that transaction and to furnish specified information to the transferor and transferee. Failure to notify us of a purchase may, in some cases, lead to the imposition of penalties. However, these reporting requirements do not apply to a sale by an individual who is a citizen of the United States and who effects the sale or exchange through a broker who will satisfy such requirements.

Constructive Termination

We will be considered to have been terminated for tax purposes if there are sales or exchanges which, in the aggregate, constitute 50% or more of the total interests in our capital and profits within a twelve-month period. For purposes of measuring whether the 50% threshold is reached, multiple sales of the same interest within a twelve-month period are counted only once. A constructive termination results in the closing of our taxable year for all unitholders. 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 result in more than twelve months of our taxable income or loss being includable in his taxable income for the year of termination. A constructive termination occurring on a date other than December 31 will result in us filing two tax returns (and unitholders receiving two Schedules K-1) for one fiscal year and the cost of the preparation of these returns will be borne by all common unitholders. We would be required to make new tax elections after a termination, including a new election under Section 754 of the Internal Revenue Code, and a termination would result in a deferral of our deductions for depreciation. A termination could also result in penalties if we were unable to determine that the termination had occurred. Moreover, a termination might either accelerate the application of, or subject us to, any tax legislation enacted before the termination.

Uniformity of Units

Because we cannot match transferors and transferees of units, we must maintain uniformity of the economic and tax characteristics of the units to a purchaser of these units. In the absence of uniformity, we may be unable to completely comply with a number of federal income tax requirements, both statutory and regulatory. A lack of uniformity can result from a literal application of Treasury Regulation Section 1.167(c)-1(a)(6). Any non-uniformity could have a negative impact on the value of the units. Please read "—Tax Consequences of Unit Ownership—Section 754 Election."

We intend to depreciate the portion of a Section 743(b) adjustment attributable to unrealized appreciation in the value of Contributed Property, to the extent of any unamortized Book-Tax Disparity, using a rate of depreciation or amortization derived from the depreciation or amortization method and useful life applied to the property's unamortized Book-Tax Disparity, or treat that portion as nonamortizable, to the extent attributable to property the common basis of which is not amortizable, consistent with the regulations under Section 743 of the Internal Revenue Code, even though that position may be inconsistent with Treasury Regulation Section 1.167(c)-1(a)(6), which is not expected to directly apply to a material portion of our assets. Please read "—Tax Consequences of Unit Ownership—Section 754 Election." To the extent that the Section 743(b) adjustment is attributable to appreciation in value in excess of the unamortized Book-Tax Disparity, we will apply the rules described in the Treasury Regulations and legislative history. If we determine that this position cannot reasonably be taken, we may adopt a depreciation and amortization position under which all purchasers acquiring units in the same month would receive depreciation and amortization deductions, whether attributable to a common basis or Section 743(b) adjustment, based upon the same applicable rate as if they had purchased a direct interest in our property. If this position is adopted, it may result in lower annual depreciation and amortization deductions than would otherwise be allowable to some unitholders and risk the loss of depreciation and amortization deductions not taken in the year that these deductions are otherwise allowable. This position will not be adopted if we determine that the loss of depreciation

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and amortization deductions will have a material adverse effect on the unitholders. If we choose not to utilize this aggregate method, we may use any other reasonable depreciation and amortization method to preserve the uniformity of the intrinsic tax characteristics of any units that would not have a material adverse effect on the unitholders. The IRS may challenge any method of depreciating the Section 743(b) adjustment described in this paragraph. If this challenge were sustained, the uniformity of units might be affected, and the gain from the sale of units might be increased without the benefit of additional deductions. Please read "—Disposition of Common Units—Recognition of Gain or Loss."

Tax-Exempt Organizations and Other Investors

Ownership of units by employee benefit plans, other tax-exempt organizations, non-resident aliens, foreign corporations and other foreign persons raises issues unique to those investors and, as described below, may have substantially adverse tax consequences to them. If you are a tax-exempt entity or a non-U.S. person, you should consult you tax advisor before investing in our common units.

Employee benefit plans and most other organizations exempt from federal income tax, including individual retirement accounts and other retirement plans, are subject to federal income tax on unrelated business taxable income. Virtually all of our income allocated to a unitholder that is a tax-exempt organization will be unrelated business taxable income and will be taxable to them.

Non-resident aliens and foreign corporations, trusts or estates that own units will be considered to be engaged in business in the United States because of the ownership of units. As a consequence, they will be required to file federal tax returns to report their share of our income, gain, loss or deduction and pay federal income tax at regular rates on their share of our net income or gain. Moreover, under rules applicable to publicly traded partnerships, we will withhold at the highest applicable effective tax rate from cash distributions made quarterly to foreign unitholders. Each foreign unitholder must obtain a taxpayer identification number from the IRS and submit that number to our transfer agent on a Form W-8BEN or applicable substitute form in order to obtain credit for these withholding taxes. A change in applicable law may require us to change these procedures.

In addition, because a foreign corporation that owns units will be treated as engaged in a U.S. trade or business, that corporation may be subject to the U.S. branch profits tax at a rate of 30%, in addition to regular federal income tax, on its share of our income and gain, as adjusted for changes in the foreign corporation's "U.S. net equity," which is effectively connected with the conduct of a U.S. trade or business. That tax may be reduced or eliminated by an income tax treaty between the United States and the country in which the foreign corporate unitholder is a "qualified resident." In addition, this type of unitholder is subject to special information reporting requirements under Section 6038C of the Internal Revenue Code.

A foreign unitholder who sells or otherwise disposes of a unit will be subject to U.S. federal income tax on gain realized from the sale or disposition of that unit to the extent the gain is effectively connected with a U.S. trade or business of the foreign unitholder. Under a ruling published by the IRS, interpreting the scope of "effectively connected income," a foreign unitholder would be considered to be engaged in a trade or business in the United States by virtue of the U.S. activities of the partnership, and part or all of that unitholder's gain would be effectively connected with that unitholder's indirect U.S. trade or business. Moreover, under the Foreign Investment in Real Property Tax Act, a foreign unitholder of a publicly traded partnership would be subject to U.S. federal income tax or withholding tax upon the sale or disposition of a unit to the extent of the unitholder's share of the partnership's U.S. real property holdings if he owns 5% or more of the units at any point during the five-year period ending on the date of such disposition. Therefore, foreign unitholders may be subject to federal income tax on gain from the sale or disposition of their units.

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Administrative Matters

Information Returns and Audit Procedures

We intend to furnish to each unitholder, within 90 days after the close of each calendar year, specific tax information, including a Schedule K-1, which describes his share of our income, gain, loss and deduction for our preceding taxable year. In preparing this information, which will not be reviewed by counsel, we will take various accounting and reporting positions, some of which have been mentioned earlier, to determine each unitholder's share of income, gain, loss and deduction. We cannot assure you that those positions will yield a result that conforms to the requirements of the Internal Revenue Code, Treasury Regulations or administrative interpretations of the IRS. Neither we nor Vinson & Elkins L.L.P. can assure prospective unitholders that the IRS will not successfully contend in court that those positions are impermissible. Any challenge by the IRS could negatively affect the value of the units.

The IRS may audit our federal income tax information returns. Adjustments resulting from an IRS audit may require each unitholder to adjust a prior year's tax liability, and possibly may result in an audit of his return. Any audit of a unitholder's return could result in adjustments not related to our returns as well as those related to our returns.

Partnerships generally are treated as separate entities for purposes of federal tax audits, judicial review of administrative adjustments by the IRS and tax settlement proceedings. The tax treatment of partnership items of income, gain, loss and deduction are determined in a partnership proceeding rather than in separate proceedings with the partners. The Internal Revenue Code requires that one partner be designated as the "Tax Matters Partner" for these purposes. Our partnership agreement names Rhino GP LLC, our general partner, as our Tax Matters Partner.

The Tax Matters Partner will make some elections on our behalf and on behalf of unitholders. In addition, the Tax Matters Partner can extend the statute of limitations for assessment of tax deficiencies against unitholders for items in our returns. The Tax Matters Partner may bind a unitholder with less than a 1% profits interest in us to a settlement with the IRS unless that unitholder elects, by filing a statement with the IRS, not to give that authority to the Tax Matters Partner. The Tax Matters Partner may seek judicial review, by which all the unitholders are bound, of a final partnership administrative adjustment and, if the Tax Matters Partner fails to seek judicial review, judicial review may be sought by any unitholder having at least a 1% interest in profits or by any group of unitholders having in the aggregate at least a 5% interest in profits. However, only one action for judicial review will go forward, and each unitholder with an interest in the outcome may participate.

A unitholder must file a statement with the IRS identifying the treatment of any item on his federal income tax return that is not consistent with the treatment of the item on our return. Intentional or negligent disregard of this consistency requirement may subject a unitholder to substantial penalties.

Nominee Reporting

Persons who hold an interest in us as a nominee for another person are required to furnish to us:

•: the name, address and taxpayer identification number of the beneficial owner and the nominee;
•: whether the beneficial owner is:
•: a person that is not a U.S. person;
•: a foreign government, an international organization or any wholly owned agency or instrumentality of either of the foregoing; or
•: a tax-exempt entity;

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•: the amount and description of units held, acquired or transferred for the beneficial owner; and
•: specific information including the dates of acquisitions and transfers, means of acquisitions and transfers, and acquisition cost for purchases, as well as the amount of net proceeds from sales.

Brokers and financial institutions are required to furnish additional information, including whether they are U.S. persons and specific information on units they acquire, hold or transfer for their own account. A penalty of $50 per failure, up to a maximum of $100,000 per calendar year, is imposed by the Internal Revenue Code for failure to report that information to us. The nominee is required to supply the beneficial owner of the units with the information furnished to us.

Accuracy-Related Penalties

An additional tax equal to 20% of the amount of any portion of an underpayment of tax that is attributable to one or more specified causes, including negligence or disregard of rules or regulations, substantial understatements of income tax and substantial valuation misstatements, is imposed by the Internal Revenue Code. No penalty will be imposed, however, for any portion of an underpayment if it is shown that there was a reasonable cause for that portion and that the taxpayer acted in good faith regarding that portion.

For individuals, a substantial understatement of income tax in any taxable year exists if the amount of the understatement exceeds the greater of 10% of the tax required to be shown on the return for the taxable year or $5,000. The amount of any understatement subject to penalty generally is reduced if any portion is attributable to a position adopted on the return:

•: for which there is, or was, "substantial authority;" or
•: as to which there is a reasonable basis and the pertinent facts of that position are disclosed on the return.

If any item of income, gain, loss or deduction included in the distributive shares of unitholders might result in that kind of an "understatement" of income for which no "substantial authority" exists, we must disclose the pertinent facts on our return. In addition, we will make a reasonable effort to furnish sufficient information for unitholders to make adequate disclosure on their returns and to take other actions as may be appropriate to permit unitholders to avoid liability for this penalty. More stringent rules apply to "tax shelters," which we do not believe includes us or any of our investments, plans or arrangements.

A substantial valuation misstatement exists if the value of any property, or the adjusted basis of any property, claimed on a tax return is 150% or more of the amount determined to be the correct amount of the valuation or adjusted basis. No penalty is imposed unless the portion of the underpayment attributable to a substantial valuation misstatement exceeds $5,000 ($10,000 for most corporations). If the valuation claimed on a return is 200% or more than the correct valuation, the penalty imposed increases to 40%. We do not anticipate making any valuation misstatements.

Reportable Transactions

If we were to engage in a "reportable transaction," we (and possibly you and others) would be required to make a detailed disclosure of the transaction to the IRS. A transaction may be a reportable transaction based upon any of several factors, including the fact that it is a type of tax avoidance transaction publicly identified by the IRS as a "listed transaction" or that it produces certain kinds of losses for partnerships, individuals, S corporations, and trusts in excess of $2 million in any single year, or $4 million in any combination of six successive tax years. Our participation in a reportable transaction could increase the likelihood that our federal income tax information return (and possibly

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your tax return) would be audited by the IRS. Please read "—Information Returns and Audit Procedures."

Moreover, if we were to participate in a reportable transaction with a significant purpose to avoid or evade tax, or in any listed transaction, you may be subject to the following provisions of the American Jobs Creation Act of 2004:

•: accuracy-related penalties with a broader scope, significantly narrower exceptions, and potentially greater amounts than described above at "—Accuracy-Related Penalties."
•: for those persons otherwise entitled to deduct interest on federal tax deficiencies, nondeductibility of interest on any resulting tax liability; and
•: in the case of a listed transaction, an extended statute of limitations.

We do not expect to engage in any "reportable transactions."

State, Local, Foreign and Other Tax Considerations

In addition to federal income taxes, you likely will be subject to other taxes, such as state, local and foreign income taxes, unincorporated business taxes, and estate, inheritance or intangible taxes that may be imposed by the various jurisdictions in which we do business or own property or in which you are a resident. Although an analysis of those various taxes is not presented here, each prospective unitholder should consider their potential impact on his investment in us. We will initially control property or do business in Colorado, Illinois, Kentucky, Ohio, Pennsylvania and West Virginia. We may also control property or do business in other jurisdictions in the future. Although you may not be required to file a return and pay taxes in some jurisdictions because your income from that jurisdiction falls below the filing and payment requirement, you will be required to file income tax returns and to pay income taxes in many of these jurisdictions in which we do business or control property and may be subject to penalties for failure to comply with those requirements. In some jurisdictions, tax losses may not produce a tax benefit in the year incurred and may not be available to offset income in subsequent taxable years. Some of the jurisdictions may require us, or we may elect, to withhold a percentage of income from amounts to be distributed to a unitholder who is not a resident of the jurisdiction. Withholding, the amount of which may be greater or less than a particular unitholder's income tax liability to the jurisdiction, generally does not relieve a nonresident unitholder from the obligation to file an income tax return. Amounts withheld will be treated as if distributed to unitholders for purposes of determining the amounts distributed by us. Please read "—Tax Consequences of Unit Ownership—Entity-Level Collections." Based on current law and our estimate of our future operations, our general partner anticipates that any amounts required to be withheld will not be material.

It is the responsibility of each unitholder to investigate the legal and tax consequences, under the laws of pertinent jurisdictions, of his investment in us. Accordingly, each prospective unitholder is urged to consult, and depend upon, his tax counsel or other advisor with regard to those matters. Further, it is the responsibility of each unitholder to file all state, local and foreign, as well as U.S. federal tax returns, that may be required of him. Vinson & Elkins L.L.P. has not rendered an opinion on the state, local or foreign tax consequences of an investment in us.

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INVESTMENT IN RHINO RESOURCE PARTNERS, L.P. BY EMPLOYEE BENEFIT PLANS

An investment in us by an employee benefit plan is subject to additional considerations because the investments of these plans are subject to the fiduciary responsibility and prohibited transaction provisions of ERISA, and restrictions imposed by Section 4975 of the Internal Revenue Code. For these purposes, the term "employee benefit plan" includes, but is not limited to, qualified pension, profit-sharing and stock bonus plans, Keogh plans, simplified employee pension plans and tax deferred annuities or IRAs established or maintained by an employer or employee organization. Among other things, consideration should be given to:

•: whether the investment is prudent under Section 404(a)(1)(B) of ERISA;
•: whether in making the investment, that plan will satisfy the diversification requirements of Section 404(a)(1)(C) of ERISA; and
•: whether the investment will result in recognition of unrelated business taxable income by the plan and, if so, the potential after-tax investment return.
•: The person with investment discretion with respect to the assets of an employee benefit plan, often called a fiduciary, should determine whether an investment in us is authorized by the appropriate governing instrument and is a proper investment for the plan.
•: Section 406 of ERISA and Section 4975 of the Internal Revenue Code prohibits employee benefit plans, and IRAs that are not considered part of an employee benefit plan, from engaging in specified transactions involving "plan assets" with parties that are "parties in interest" under ERISA or "disqualified persons" under the Internal Revenue Code with respect to the plan.
•: In addition to considering whether the purchase of common units is a prohibited transaction, a fiduciary of an employee benefit plan should consider whether the plan will, by investing in us, be deemed to own an undivided interest in our assets, with the result that our general partner also would be fiduciaries of the plan and our operations would be subject to the regulatory restrictions of ERISA, including its prohibited transaction rules, as well as the prohibited transaction rules of the Internal Revenue Code.
•: The Department of Labor regulations provide guidance with respect to whether the assets of an entity in which employee benefit plans acquire equity interests would be deemed "plan assets" under some circumstances. Under these regulations, an entity's assets would not be considered to be "plan assets" if, among other things:
•: the equity interests acquired by employee benefit plans are publicly offered securities—i.e., the equity interests are widely held by 100 or more investors independent of the issuer and each other, freely transferable and registered under some provisions of the federal securities laws;
•: the entity is an "operating company,"—i.e., it is primarily engaged in the production or sale of a product or service other than the investment of capital either directly or through a majority owned subsidiary or subsidiaries; or
•: there is no significant investment by benefit plan investors, which is defined to mean that less than 25% of the value of each class of equity interest, disregarding some interests held by our general partner, its affiliates, and some other persons, is held by the employee benefit plans referred to above, IRAs and other employee benefit plans not subject to ERISA, including governmental plans.

Our assets should not be considered "plan assets" under these regulations because it is expected that the investment will satisfy the requirements in the first bullet.

Plan fiduciaries contemplating a purchase of common units should consult with their own counsel regarding the consequences under ERISA and the Internal Revenue Code in light of the serious penalties imposed on persons who engage in prohibited transactions or other violations.

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UNDERWRITING

Lehman Brothers Inc. is acting as the representative of the underwriters and the sole book-running manager of this offering. Under the terms of an underwriting agreement, which is filed as an exhibit to the registration statement, each of the underwriters named below has severally agreed to purchase from us the respective number of common units shown opposite its name below:

Underwriters		Number of Units
Lehman Brothers Inc.


	Total	5,000,000

The underwriting agreement provides that the underwriters' obligation to purchase the common units depends on the satisfaction of the conditions contained in the underwriting agreement including:

•: the obligation to purchase all of the common units offered hereby (other than those common units covered by their option to purchase additional common units as described below), if any of the common units are purchased;
•: the representations and warranties made by us to the underwriters are true;
•: there is no material change in our business or the financial markets; and
•: we deliver customary closing documents to the underwriters.

Commissions and Expenses

The following table summarizes the underwriting discounts and commissions we will pay to the underwriters. These amounts are shown assuming both no exercise and full exercise of the underwriters' option to purchase additional common units. The underwriting fee is the difference between the initial price to the public and the amount the underwriters pay to us for the common units.

		No Exercise		Full Exercise
Per unit
Total

The representative of the underwriters has advised us that the underwriters propose to offer the common units directly to the public at the public offering price on the cover of this prospectus and to selected dealers, which may include the underwriters, at such offering price less a selling concession not in excess of $ per unit. After the offering, the representative may change the offering price and other selling terms.

The expenses of the offering that are payable by us are estimated to be $1.0 million (excluding the underwriting discounts).

Option to Purchase Additional Units

We have granted the underwriters an option exercisable for 30 days after the date of this prospectus, to purchase, from time to time, in whole or in part, up to an aggregate of 750,000 common units at the public offering price less underwriting discounts and commissions. This option may be

200

exercised if the underwriters sell more than 5,000,000 common units in connection with this offering. To the extent that this option is exercised, each underwriter will be obligated, subject to certain conditions, to purchase its pro rata portion of these additional common units based on the underwriter's underwriting commitment in the offering as indicated in the table at the beginning of this section.

Lock-Up Agreements

Rhino Energy Holdings LLC, the executive officers and directors of our general partner, and we have agreed, without the prior written consent of Lehman Brothers Inc., not to directly or indirectly, (1) offer for sale, sell, pledge, or otherwise dispose of (or enter into any transaction or device that is designed to, or could be expected to, result in the disposition by any person at any time in the future of) any common units (including, without limitation, common units that may be deemed to be beneficially owned by us or them in accordance with the rules and regulations of the Securities and Exchange Commission and common units that may be issued upon exercise of any options or warrants) or securities convertible into or exercisable or exchangeable for common units, (2) enter into any swap or other derivatives transaction that transfers to another, in whole or in part, any of the economic consequences of ownership of common units, whether any such transaction described in clause (1) or (2) above is to be settled by delivery of common units or other securities, in cash or otherwise, (3) cause to be filed a registration statement, including any amendments thereto, with respect to the registration of any common units or securities convertible, exercisable or exchangeable into common units or any of our other securities, or (4) publicly disclose the intention to do any of the foregoing for a period of 180 days after the date of this prospectus.

The 180-day restricted period described in the preceding paragraph will be extended if:

•: during the last 17 days of the 180-day restricted period we issue an earnings release or material news or a material event relating to us occurs; or
•: prior to the expiration of the 180-day restricted period, we announce that we will release earnings results during the 16-day period beginning on the last day of the 180-day period,

in which case the restrictions described in the preceding paragraph will continue to apply until the expiration of the 18-day period beginning on the issuance of the earnings release or the announcement of the material news or occurrence of a material event, unless such extension is waived in writing by Lehman Brothers Inc.

The restrictions described in this paragraph do not apply to:

•: the issuance and sale of common units by us to the underwriters pursuant to the underwriting agreement; or
•: the issuance and sale of common units, phantom units, restricted units and options under our existing employee benefits plans, including sales pursuant to "cashless-broker" exercises of options to purchase common units in accordance with such plans as consideration for the exercise price and withholding taxes applicable to such exercises.

Lehman Brothers Inc., in its sole discretion, may release the common units and other securities subject to the lock-up agreements described above in whole or in part at any time with or without notice. When determining whether or not to release common units and other securities from lock-up agreements, Lehman Brothers Inc. will consider, among other factors, the holder's reasons for requesting the release, the number of common units and other securities for which the release is being requested and market conditions at the time.

201

Offering Price Determination

Prior to this offering, there has been no public market for our common units. The initial public offering price will be negotiated between the representatives and us. In determining the initial public offering price of our common units, the representatives will consider:

•: the history and prospects for the industry in which we compete;
•: our financial information;
•: the ability of our management and our business potential and earning prospects;
•: the prevailing securities markets at the time of this offering; and
•: the recent market prices of, and the demand for, publicly traded common units of generally comparable master limited partnerships.

Indemnification

We, our subsidiaries and our general partner have agreed to indemnify the underwriters against certain liabilities, including liabilities under the Securities Act of 1933 and liabilities incurred in connection with the directed unit program referred to below, and to contribute to payments that the underwriters may be required to make for these liabilities.

Stabilization, Short Positions and Penalty Bids

The representative may engage in stabilizing transactions, short sales and purchases to cover positions created by short sales, and penalty bids or purchases for the purpose of pegging, fixing or maintaining the price of the common units, in accordance with Regulation M under the Securities Exchange Act of 1934:

•: Stabilizing transactions permit bids to purchase the underlying security so long as the stabilizing bids do not exceed a specified maximum.
•: A short position involves a sale by the underwriters of common units in excess of the number of units the underwriters are obligated to purchase in the offering, which creates the syndicate short position. This short position may be either a covered short position or a naked short position. In a covered short position, the number of common units involved in the sales made by the underwriters in excess of the number of units they are obligated to purchase is not greater than the number of units that they may purchase by exercising their option to purchase additional common units. In a naked short position, the number of units involved is greater than the number of units in their option to purchase additional common units. The underwriters may close out any short position by either exercising their option to purchase additional common units and/or purchasing common units in the open market. In determining the source of common units to close out the short position, the underwriters will consider, among other things, the price of units available for purchase in the open market as compared to the price at which they may purchase units through their option to purchase additional common units. A naked short position is more likely to be created if the underwriters are concerned that there could be downward pressure on the price of the common units in the open market after pricing that could adversely affect investors who purchase in the offering.
•: Syndicate covering transactions involve purchases of the common units in the open market after the distribution has been completed in order to cover syndicate short positions.
•: Penalty bids permit the representatives to reclaim a selling concession from a syndicate member when the common units originally sold by the syndicate member is purchased in a stabilizing or syndicate covering transaction to cover syndicate short positions.

202

These stabilizing transactions, syndicate covering transactions and penalty bids may have the effect of raising or maintaining the market price of our common units or preventing or retarding a decline in the market price of the common units. As a result, the price of the common units may be higher than the price that might otherwise exist in the open market. These transactions may be effected on the NASDAQ Global Select Market or otherwise and, if commenced, may be discontinued at any time.

Neither we nor any of the underwriters make any representation or prediction as to the direction or magnitude of any effect that the transactions described above may have on the price of the common units. In addition, neither we nor any of the underwriters make representation that the representative will engage in these stabilizing transactions or that any transaction, once commenced, will not be discontinued without notice.

Electronic Distribution

A prospectus in electronic format may be made available on the Internet sites or through other online services maintained by one or more of the underwriters and/or selling group members participating in this offering, or by their affiliates. In those cases, prospective investors may view offering terms online and, depending upon the particular underwriter or selling group member, prospective investors may be allowed to place orders online. The underwriters may agree with us to allocate a specific number of common units for sale to online brokerage account holders. Any such allocation for online distributions will be made by the representative on the same basis as other allocations.

Other than the prospectus in electronic format, the information on any underwriter's or selling group member's web site and any information contained in any other web site maintained by an underwriter or selling group member is not part of the prospectus or the registration statement of which this prospectus forms a part, has not been approved and/or endorsed by us or any underwriter or selling group member in its capacity as underwriter or selling group member and should not be relied upon by investors.

NASDAQ Global Select Market

We intend to apply to list our common units for quotation on the NASDAQ Global Select Market under the symbol "RRLP."

Discretionary Sales

The underwriters have informed us that they do not intend to confirm sales to discretionary accounts that exceed 5% of the total number of shares offered by them.

Stamp Taxes

If you purchase common units offered in this prospectus, you may be required to pay stamp taxes and other charges under the laws and practices of the country of purchase, in addition to the offering price listed on the cover page of this prospectus.

Relationships/NASD Conduct Rules

The underwriters may in the future perform investment banking and advisory services for us from time to time for which they may in the future receive customary fees and expense reimbursement.

Because the Financial Industry Regulatory Authority, or FINRA, views the common units offered hereby as interests in a direct participation program, the offering is being made in compliance with Rule 2810 of the NASD's Conduct Rules (which are part of the FINRA Rules). Investor suitability with

203

respect to the common units should be judged similarly to the suitability with respect to other securities that are listed for trading on a national securities exchange.

Selling Restrictions

Public Offer Selling Restrictions Under the Prospectus Directive

In relation to each member state of the European Economic Area that has implemented the Prospectus Directive (each, a relevant member state), with effect from and including the date on which the Prospectus Directive is implemented in that relevant member state (the relevant implementation date), an offer of securities described in this prospectus may not be made to the public in that relevant member state other than:

•: to any legal entity that is authorized or regulated to operate in the financial markets or, if not so authorized or regulated, whose corporate purpose is solely to invest in securities;
•: to any legal entity that has two or more of (1) an average of at least 250 employees during the last financial year; (2) a total balance sheet of more than €43,000,000 and (3) an annual net turnover of more than €50,000,000, as shown in its last annual or consolidated accounts;
•: to fewer than 100 natural or legal persons (other than qualified investors as defined in the Prospectus Directive) subject to obtaining the prior consent of the representative; or
•: in any other circumstances that do not require the publication of a prospectus pursuant to Article 3 of the Prospectus Directive,

provided that no such offer of securities shall require us or any underwriter to publish a prospectus pursuant to Article 3 of the Prospectus Directive.

For purposes of this provision, the expression an "offer of securities to the public" in any relevant member state means the communication in any form and by any means of sufficient information on the terms of the offer and the securities to be offered so as to enable an investor to decide to purchase or subscribe the securities, as the expression may be varied in that member state by any measure implementing the Prospectus Directive in that member state, and the expression "Prospectus Directive" means Directive 2003/71/EC and includes any relevant implementing measure in each relevant member state.

We have not authorized and do not authorize the making of any offer of securities through any financial intermediary on their behalf, other than offers made by the underwriters with a view to the final placement of the securities as contemplated in this prospectus. Accordingly, no purchaser of the securities, other than the underwriters, is authorized to make any further offer of the securities on behalf of us or the underwriters.

Selling Restrictions Addressing Additional United Kingdom Securities Laws

This prospectus is only being distributed to, and is only directed at, persons in the United Kingdom that are qualified investors within the meaning of Article 2(1)(e) of the Prospectus Directive ("Qualified Investors") that are also (i) investment professionals falling within Article 19(5) of the Financial Services and Markets Act 2000 (Financial Promotion) Order 2005 (the "Order") or (ii) high net worth entities, and other persons to whom it may lawfully be communicated, falling within Article 49(2)(a) to (d) of the Order (all such persons together being referred to as "relevant persons"). This prospectus and its contents are confidential and should not be distributed, published or reproduced (in whole or in part) or disclosed by recipients to any other persons in the United Kingdom. Any person in the United Kingdom that is not a relevant persons should not act or rely on this document or any of its contents.

204

VALIDITY OF THE COMMON UNITS

The validity of the common units will be passed upon for us by Vinson & Elkins L.L.P., New York, New York. Certain legal matters in connection with the common units offered hereby will be passed upon for the underwriters by Andrews Kurth LLP, Houston, Texas.

EXPERTS

The consolidated financial statements of Rhino Energy LLC (the "Company") as of December 31, 2006 and 2007, and for the year ended March 31, 2006, the nine months ended December 31, 2006 and the year ended December 31, 2007 included in this prospectus and the related consolidated financial statement schedule included elsewhere in this registration statement have been audited by Deloitte & Touche LLP, an independent registered public accounting firm, as stated in their reports appearing herein and elsewhere in this registration statement (which report regarding the consolidated financial statements expresses an unqualified opinion and includes explanatory paragraphs concerning the adoption of SFAS No. 158, Employers' Accounting for Defined Benefit Pension and Other Postretirement Plans—an amendment of FASB Statements No. 87, 88, 106 and 132(R), and a change in the Company's fiscal year end). Such consolidated financial statements and consolidated financial statement schedule have been so included in reliance upon the reports of such firm given upon their authority as experts in accounting and auditing.

The statements of financial position of Rhino Resource Partners, L.P. as of December 31, 2006 and 2007, included in this prospectus, have been audited by Deloitte & Touche LLP, an independent registered public accounting firm, as stated in their report appearing herein. Such statements of financial position are so included in reliance upon the report of such firm given upon their authority as experts in accounting and auditing.

The statements of financial position of Rhino GP LLC as of December 31, 2006 and 2007, included in this prospectus, have been audited by Deloitte & Touche LLP, an independent registered public accounting firm, as stated in their report appearing herein. Such statements of financial position are so included in reliance upon the report of such firm given upon their authority as experts in accounting and auditing.

The information appearing in this prospectus concerning estimates of our proven and probable coal reserves, non-reserve coal deposits, proven and probable limestone reserves and non-reserve limestone deposits was prepared by Marshall Miller and has been included herein upon the authority of this firm as an expert.

WHERE YOU CAN FIND MORE INFORMATION

We have filed with the SEC a registration statement on Form S-1 regarding the common units. This prospectus does not contain all of the information found in the registration statement. For further information regarding us and the common units offered in this prospectus, you may desire to review the full registration statement, including its exhibits. The registration statement, including the exhibits, may be inspected and copied at the public reference facilities maintained by the SEC at 100 F Street, N.E., Room 1580, Washington, D.C. 20549. Copies of this material can also be obtained upon written request from the Public Reference Section of the SEC at 100 F Street, N.E., Room 1580, Washington, D.C. 20549, at prescribed rates or from the SEC's web site on the Internet at http://www.sec.gov. Please call the SEC at 1-800-SEC-0330 for further information on public reference rooms.

As a result of the offering, we will file with or furnish to the SEC periodic reports and other information. These reports and other information may be inspected and copied at the public reference facilities maintained by the SEC or obtained from the SEC's website as provided above. Our website on the Internet will be located at http://www.rhinolp.com, and we expect to make our periodic reports

205

and other information filed with or furnished to the SEC available, free of charge, through our website, as soon as reasonably practicable after those reports and other information are electronically filed with or furnished to the SEC. Information on our website or any other website is not incorporated by reference into this prospectus and does not constitute a part of this prospectus.

We intend to furnish or make available to our unitholders annual reports containing our audited financial statements prepared in accordance with GAAP. Our annual report will contain a detailed statement of any transactions with our general partner or its affiliates, and of fees, commissions, compensation and other benefits paid, or accrued to our general partner or its affiliates for the fiscal year completed, showing the amount paid or accrued to each recipient and the services performed. We also intend to furnish or make available to our unitholders quarterly reports containing our unaudited interim financial information, including the information required by Form 10-Q, for the first three fiscal quarters of each fiscal year.

FORWARD-LOOKING STATEMENTS

Some of the information in this prospectus may contain forward-looking statements. These statements can be identified by the use of forward-looking terminology including "will," "may," "believe," "expect," "anticipate," "estimate," "continue," or other similar words. These statements discuss future expectations, contain projections of results of operations or of financial condition, or state other "forward-looking" information. These forward-looking statements involve risks and uncertainties. When considering these forward-looking statements, you should keep in mind the risk factors and other cautionary statements in this prospectus. The risk factors and other factors noted throughout this prospectus could cause our actual results to differ materially from those contained in any forward-looking statement.

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INDEX TO FINANCIAL STATEMENTS


RHINO RESOURCE PARTNERS, L.P.
	UNAUDITED PRO FORMA CONSOLIDATED FINANCIAL STATEMENTS
		Introduction	F-2
		Unaudited Pro Forma Consolidated Statement of Financial Position as of December 31, 2007	F-4
		Unaudited Pro Forma Consolidated Statement of Operations for the Year ended December 31, 2007	F-5
		Notes to Unaudited Pro Forma Consolidated Financial Statements	F-6
RHINO ENERGY LLC
	CONSOLIDATED FINANCIAL STATEMENTS
		Report of Independent Registered Public Accounting Firm	F-9
		Consolidated Statements of Financial Position as of December 31, 2006 and 2007	F-10
		Consolidated Statements of Operations for the Year Ended March 31, 2006, the Nine Months Ended December 31, 2006 and the Year Ended December 31, 2007	F-11
		Consolidated Statements of Members' Equity for the Year Ended March 31, 2006, the Nine Months Ended December 31, 2006 and the Year Ended December 31, 2007	F-12
		Consolidated Statements of Cash Flows for the Year Ended March 31, 2006, the Nine Months Ended December 31, 2006 and the Year Ended December 31, 2007	F-13
		Notes to Consolidated Financial Statements	F-14
RHINO RESOURCE PARTNERS, L.P.
	STATEMENTS OF FINANCIAL POSITION
		Report of Independent Registered Public Accounting Firm	F-32
		Statements of Financial Position as of December 31, 2006 and 2007	F-33
		Note to the Statements of Financial Position	F-34
RHINO GP LLC
	STATEMENTS OF FINANCIAL POSITION
		Report of Independent Registered Public Accounting Firm	F-35
		Statements of Financial Position as of December 31, 2006 and 2007	F-36
		Notes to the Statements of Financial Position	F-37

F-1

RHINO RESOURCE PARTNERS, L.P.

UNAUDITED PRO FORMA CONSOLIDATED FINANCIAL STATEMENTS

Introduction

Rhino Resource Partners, L.P. (the "Partnership") will own and operate the business of Rhino Energy LLC and its subsidiaries (collectively "Rhino Energy") effective with the issuance by the Partnership of its common units to the public. The contribution of the business of Rhino Energy to the Partnership will be recorded at historical cost as it is considered to be a reorganization of entities under common control. The unaudited pro forma consolidated financial statements for the Partnership have been derived from the historical consolidated statements of financial position and operations of Rhino Energy set forth elsewhere in this prospectus and are qualified in their entirety by reference to such historical consolidated statements of financial position and operations and related notes contained therein. The unaudited pro forma consolidated financial statements have been prepared on the basis that the Partnership will be treated as a partnership for federal income tax purposes. The unaudited pro forma consolidated financial statements should be read in conjunction with the notes accompanying such financial statements and with the historical consolidated statements of financial position and operations and related notes set forth elsewhere in this prospectus.

The accompanying unaudited pro forma consolidated financial statements reflect the following transactions:

•: the distribution by Rhino Energy LLC of its ownership interests in CAM-Colorado LLC, an entity that owns certain properties located in Colorado that will not be retained by the Partnership, to NR Energy LLC, an entity owned by certain investment funds managed by Wexford Capital LLC ("Wexford Funds");
•: the contribution by Rhino Energy Holdings LLC, which is also owned by certain Wexford Funds, of 100% of the ownership interests in Rhino Energy LLC to the Partnership;
•: the issuance by the Partnership to Rhino Energy Holdings LLC of an aggregate of 27,925,200 common units and 3,741,500 subordinated units, representing a combined 84.6% limited partner interest in the Partnership;
•: the issuance by the Partnership to its general partner of the incentive distribution rights, which entitle the holder to increasing percentages, up to a maximum of 10%, of the cash the Partnership distributes in excess of $0.425 per unit per quarter. The general partner will also maintain its 2% general partner interest in the Partnership;
•: the issuance by the Partnership to the public of 5,000,000 common units, representing a 13.4% limited partner interest in the Partnership;
•: the repayment of approximately $67.0 million of indebtedness under Rhino Energy's current credit facility and the distribution of approximately $25.0 million of the proceeds from the offering to Rhino Energy Holdings LLC as reimbursement for capital expenditures (expenditures that were capitalized for federal income tax purposes) incurred within the prior 24 months by Rhino Energy LLC with respect to the assets to be contributed to the Partnership upon the closing of this offering; and
•: the payment of the estimated underwriting discount and offering expenses of approximately $8.0 million.

The unaudited pro forma consolidated statement of financial position for the year ended December 31, 2007 assumes the contribution, offering and related transactions occurred as of December 31, 2007. The unaudited pro forma consolidated statement of operations for the year ended

F-2

December 31, 2007 assumes that the contribution, offering and related transactions occurred on January 1, 2007.

The adjustments are based upon currently available information and certain estimates and assumptions; therefore, actual adjustments will differ from the pro forma adjustments. However, management believes that the assumptions provide a reasonable basis for presenting the significant effects of the transactions as contemplated and that the pro forma adjustments give appropriate effect to those assumptions and are properly applied in the unaudited pro forma consolidated financial information.

F-3

RHINO RESOURCE PARTNERS, L.P.

UNAUDITED PRO FORMA CONSOLIDATED STATEMENT OF FINANCIAL POSITION
AS OF DECEMBER 31, 2007

						Pro Forma Adjustments
			Rhino Energy LLC Historical			Distribution of CAM-Colorado LLC			Completion of this Offering			Rhino Resource Partners, L.P. Pro Forma
ASSETS
	CURRENT ASSETS:
	Cash and cash equivalents		$	3,583,395		$	—		$	100,000,000 (8,000,000) (25,000,000) (67,000,000)	(a) (b) (d) (c)	$	3,583,395
	Accounts receivable, net of allowance for doubtful accounts of $175,242			41,417,830			—			—			41,417,830
	Inventories			7,587,585			—			—			7,587,585
	Advance royalties, current portion			1,205,683			—			—			1,205,683
		Prepaid expenses and other		5,686,064			(4,183)	(e)		—			5,681,881

		Total current assets		59,480,557			(4,183	)		—			59,476,374
	PROPERTY, PLANT AND EQUIPMENT:
		At cost, including coal properties, mine development and contract costs		289,562,564			(17,787,777)	(e)		—			271,774,787
		Less accumulated depreciation, depletion and amortization		(77,905,483	)		—			—			(77,905,483	)

		Net property, plant and equipment		211,657,081			(17,787,777	)		—			193,869,304
		Advance royalties, net of current portion		2,392,718			—			—			2,392,718
		Other non-current assets		2,461,878			—			—			2,461,878

	TOTAL		$	275,992,234		$	(17,791,960	)	$	—		$	258,200,274

LIABILITIES AND EQUITY
	CURRENT LIABILITIES:
	Accounts payable		$	14,465,527		$	(107,842)	(e)	$	—		$	14,357,685
	Accrued expenses and other			16,850,040			(391,429)	(e)		700,000	(h)		17,158,611
	Current portion of long-term debt			10,161,633			—			—			10,161,633
	Current portion of asset retirement obligations			2,582,646			—			—			2,582,646
	Current portion of postretirement benefits			91,785			—			—			91,785
	Current portion of deferred revenue			580,066			—			—			580,066

	Total current liabilities			44,731,697			(499,271	)		—			44,932,426
NON-CURRENT LIABILITIES
	Long-term debt			73,792,083			—			(67,000,000)	(c)		6,792,083
	Asset retirement obligations			33,804,753			—			—			33,804,753
	Other non-current liabilities			1,166,656			—			—			1,166,656
	Postretirement benefits			4,656,507			—			—			4,656,507

	Total non-current liabilities			113,419,999			—			(67,000,000	)		46,419,999

	Total liabilities			158,151,696			(499,271	)		(67,000,000	)		91,352,425

MEMBERS' EQUITY:
	Members' investment			23,627,194			(17,273,597)	(e)		(72,653,597) (700,000) 100,000,000 (25,000,000) (8,000,000)	(f) (h) (a) (d) (b)		—
	Retained earnings			93,624,968			(19,092)	(e)		(93,605,876)	(f)		—
	Accumulated other comprehensive income			588,376			—			(588,376)	(f)		—

	Total members' equity			117,840,538			(17,292,689	)		(100,547,849	)		—

PARTNERS' EQUITY:
	Limited partner interests
		Common Units (32,925,200 units)		—			—			146,308,336	(f)		146,308,336
		Subordinated Units (3,741,500 units)		—			—			16,625,947	(f)		16,625,947
	General partner interest (748,300 unit equivalent)			—			—			3,325,189	(f)		3,325,189
	Accumulated other comprehensive income			—			—			588,376	(f)		588,376

	Total partners' equity			—			—			166,847,849			166,847,849

TOTAL			$	275,992,234		$	(17,791,960	)	$	—		$	258,200,274

See notes to unaudited pro forma consolidated financial statements.

F-4

RHINO RESOURCE PARTNERS, L.P.

UNAUDITED PRO FORMA CONSOLIDATED STATEMENT OF OPERATIONS
FOR THE YEAR ENDED DECEMBER 31, 2007

						Pro Form Adjustments
			Rhino Energy LLC Historical			Distribution of CAM-Colorado LLC			Completion of this Offering			Rhino Resources Partners, L.P. Pro Forma
REVENUES:
	Coal revenues		$	394,078,915		$	—		$	—		$	394,078,915
	Freight and handling revenues			4,052,430			—			—			4,052,430
	Other revenues			5,320,452			(8,600	) (e)		—			5,311,852

		Total revenues		403,451,797			(8,600	)		—			403,443,197

COSTS AND EXPENSES:
	Cost of operations (exclusive of depreciation, depletion and amortization shown separately below)			318,520,554			11,087	(e)		—			318,531,641
	Freight and handling costs			4,020,747			—			—			4,020,747
	Depreciation, depletion and amortization			30,749,773			—			—			30,749,773
	Selling, general and administrative			15,370,333			(595	) (e)		—			15,369,738
	(Gain) loss on retirement of advance royalties			(115,277	)		—			—			(115,277	)
	(Gain) loss on sale of assets			(944,303	)		—			—			(944,303	)

	Total costs and expenses			367,601,827			10,492			—			367,612,319

INCOME (LOSS) FROM OPERATIONS				35,849,970			(19,092	)		—			35,830,878
INTEREST AND OTHER INCOME (EXPENSE)
	Interest expense			(5,579,224	)		—			3,778,420 (g	)		(1,800,804	)
	Interest income			316,710			—			—			316,710
	Other—net			—			—			—			—

		Total interest and other expenses		(5,262,514	)		—			3,778,420			(1,484,094	)

INCOME (LOSS) BEFORE INCOME TAXES				30,587,456			(19,092	)		3,778,420			34,346,784
INCOME TAX (BENEFIT) EXPENSE				(126,308	)		—			—			(126,308	)

NET INCOME (LOSS)			$	30,713,764		$	(19,092	)	$	3,778,420		$	34,473,092

	General partner's interest in net income											$	689,462
	Limited partners' interest in net income											$	33,783,630
Net income per limited partner unit, basic and diluted:
	Common units											$	1.03
	Subordinated units											$	—
Weighted average number of limited partner units outstanding, basic and diluted:
	Common units												32,925,200
	Subordinated units												3,741,500

See notes to unaudited pro forma consolidated financial statements.

F-5

RHINO RESOURCE PARTNERS, L.P.

NOTES TO UNAUDITED PRO FORMA CONSOLIDATED FINANCIAL STATEMENTS
AS OF AND FOR THE YEAR ENDED DECEMBER 31, 2007

1. ORGANIZATION AND BASIS OF PRESENTATION

The unaudited pro forma consolidated financial information is derived from the historical consolidated statements of financial position and operations of Rhino Energy LLC and its subsidiaries (collectively "Rhino Energy").

The unaudited pro forma consolidated financial statements reflect the following transactions:

•: the distribution by Rhino Energy LLC of its ownership interests in CAM-Colorado LLC, an entity that owns certain properties located in Colorado that will not be retained by the Partnership, to NR Energy LLC, an entity owned by certain Wexford Funds;
•: the contribution by Rhino Energy Holdings LLC, which is also owned by certain Wexford Funds, of 100% of the ownership interests in Rhino Energy LLC to the Partnership;
•: the issuance by the Partnership to Rhino Energy Holdings LLC of an aggregate of 27,925,200 common units and 3,741,500 subordinated units, representing a combined 84.6% limited partner interest in the Partnership;
•: the issuance by the Partnership to its general partner of the incentive distribution rights, which entitle the holder to increasing percentages, up to a maximum of 10%, of the cash the Partnership distributes in excess of $0.425 per unit per quarter. The general partner will also maintain its 2% general partner interest in the Partnership;
•: the issuance by the Partnership to the public of 5,000,000 common units, representing a 13.4% limited partner interest in the Partnership;
•: the repayment of $67.0 million of indebtedness under Rhino Energy's current credit facility and the distribution of $25.0 million of the proceeds from the offering to Rhino Energy Holdings LLC as reimbursement for capital expenditures (expenditures that were capitalized for federal income tax purposes) incurred within the prior 24 months by Rhino Energy LLC with respect to the assets to be contributed to the Partnership upon the closing of this offering; and
•: the payment of the estimated underwriting discount and offering expenses of $8.0 million.

Upon the consummation of this offering, the Partnership anticipates to incur incremental selling, general and administrative expenses related to becoming a separate public entity (e.g., cost of tax return preparation, annual and quarterly reports to unitholders, stock exchange listing fees and registrar and transfer agent fees) in an annual amount of approximately $3.0 million. The unaudited pro forma consolidated financial statements do not reflect this $3.0 million in incremental selling, general and administrative expenses. The unaudited pro forma consolidated financial statements assume that the underwriters' option to purchase additional common units is not exercised.

2. PRO FORMA ADJUSTMENTS AND ASSUMPTIONS

(a): Reflects the gross proceeds to Rhino Resource Partners, L.P. of $100.0 million for the issuance and sale of 5,000,000 common units at an assumed initial public offering price of $20.00 per unit. An increase or decrease in the initial public offering price by $1.00 per common unit would cause the net proceeds from this offering, after deducting the underwriting discount and offering expenses payable by us, to increase or decrease, respectively, by approximately $4.7 million (or

F-6

RHINO RESOURCE PARTNERS, L.P.

NOTES TO UNAUDITED PRO FORMA CONSOLIDATED FINANCIAL STATEMENTS
AS OF AND FOR THE YEAR ENDED DECEMBER 31, 2007 (Continued)

approximately $5.3 million if the underwriters exercise their option to purchase additional common units in full).

(b): Reflects the payment of the estimated underwriting discount and offering expenses of $8.0 million.
(c): Reflects repayment of indebtedness outstanding under the credit facility of $67.0 million at December 31, 2007. The $67.0 million of indebtedness under the credit facility is a senior secured credit facility incurred for working capital needs and the acquisitions of coal properties, mining equipment and other capital needs.
(d): Reflects distribution of $25.0 million of the proceeds to Rhino Energy Holdings LLC as reimbursement for capital expenditures.
(e): Reflects the distribution of ownership interests in CAM-Colorado LLC to NR Energy LLC, including property, plant and equipment of $17.8 million, and current liabilities of $0.5 million as of December 31, 2007.
(f): Reflects the elimination of members' interest converted into general and limited partner interests. The limited partner interests consists of common units representing an 88.0% limited partner interest, subordinated units representing a 10.0% limited partner interest and the 2.0% general partner interest.
(g): Reflects net change in interest expense as a result of the repayment of borrowing under the current credit facility of $67.0 million at January 1, 2007. The individual components of the net change in interest expense are as follows:

		Year Ended December 31, 2007
Revolving credit facility(1)		$	523,833
Commitment fee on the unused portion of the credit facility(2)			265,029
Letters of Credit(3)			126,368
Note payable to Applied Financials(4)			62,044
Note payable to H&L Construction Co., Inc.(5)			481,780
Note payable to National City Bank(6)			298,214
Note payable to others(7)			43,536

Total pro forma interest expense			1,800,804
	Less: Historical interest expense		(5,579,224	)

Pro forma interest expense adjustment		$	(3,778,420	)

(1): Reflects pro forma interest expense at LIBOR of 5.24% plus 1.31% on estimated outstanding balance on the revolving credit facility in the amount of $8.0 million as of January 1, 2007. A change of 1.0% would have increased or decreased pro forma net interest expense by $0.1 million.
(2): Reflects pro forma commitment fee at 0.25% on estimated unused portion of the credit facility in the amount of $106.0 million as of January 1, 2007.
(3): Reflects pro forma interest expense at 1.15% on the letter of credit facility in the amount of approximately $11.0 million as of January 1, 2007.
(4): Reflects pro forma interest expense at 5.93% on the note payable to Applied Financials in the amount of $1.0 million as of January 1, 2007.

F-7

RHINO RESOURCE PARTNERS, L.P.

NOTES TO UNAUDITED PRO FORMA CONSOLIDATED FINANCIAL STATEMENTS
AS OF AND FOR THE YEAR ENDED DECEMBER 31, 2007 (Continued)

(5): Reflects imputed interest at 6.50% on the note payable to H&L Construction Co., Inc. in the amount of $7.4 million as of January 1, 2007.
(6): Reflects pro forma interest expense at 6.80% on the note payable to National City Bank in the amount of $4.4 million as of January 1, 2007.
(7): Reflects pro forma interest expense at 5.99% on the note payable to National City Bank in the amount of $0.7 million as of January 1, 2007.
(h): Reflects a $700,000 one-time cash bonus payment to executive officers payable within 30 days of completion of the initial public offering.

3. PRO FORMA NET INCOME PER UNIT

Pro forma net income per limited partner unit is determined by dividing the pro forma net income that would have been allocated in accordance with the net income and loss allocation provisions of the limited partnership agreement to the common and subordinated unitholders under the two-class method, after deducting the general partner's 2% interest in pro forma net income, by the number of common and subordinated units expected to be outstanding at the closing of this offering. For purposes of this calculation, we assumed the number of common and subordinated units outstanding were 32,925,200 and 3,741,500, respectively. All units were assumed to have been outstanding since January 1, 2007. Basic and diluted pro forma net income per unit are equal as there will be no dilutive units at the closing of the offering. Pursuant to the partnership agreement, to the extent that the quarterly distributions exceed certain targets, the general partner is entitled to receive certain incentive distributions that will result in more net income proportionately being allocated to the general partner than to the holders of common and subordinated units. The pro forma net income per unit calculations assume that no incentive distributions were made to the general partner because no such distribution would have been paid based upon the pro forma available cash from operating surplus for the year ended December 31, 2007. Our pro forma calculations did not give effect to the option to purchase additional common units that may be exercised by the underwriters.

Emerging Issues Task Force Issue No. 03-06, Participating Securities and the Two-Class Method under FASB Statement No. 128 ("EITF 03-06"), addresses the computation of earnings per share by entities that have issued securities other than common stock that contractually entitle the holder to participate in dividends and earnings of the entity. EITF 03-06 provides that the general partner's interest in net income is to be calculated based on the amount that would be allocated to the general partner if all the net income for the period were distributed, and not on the basis of actual cash distributions for the period. The application of EITF 03-06 may have an impact on earnings per limited partner unit in future periods if there are material differences between net income and actual cash distributions or if other participating securities are issued.

Staff Accounting Bulletin 1:B:3 requires that certain distributions to owners prior to or coincident with an initial public offering be considered as distributions in contemplation of that offering. Upon the consummation of this offering, we intend to distribute $25.0 million to Rhino Energy Holdings LLC as reimbursement for certain capital expenditures. This distribution will be paid with the proceeds of the offering. Assuming additional common units were issued to give effect to this distribution, pro forma net income per common unit would have been $0.99 and pro forma net income per subordinated unit would have been $0.00 for the year ended December 31, 2007.

F-8

REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

To the Members of Rhino Energy LLC
Lexington, Kentucky

We have audited the accompanying consolidated statements of financial position of Rhino Energy LLC (the "Company") as of December 31, 2006 and 2007, and the related consolidated statements of operations, members' equity, and cash flows for the year ended March 31, 2006, the nine months ended December 31, 2006 and the year ended December 31, 2007. These financial statements are the responsibility of the Company's management. Our responsibility is to express an opinion on these financial statements based on our audits.

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

In our opinion, such consolidated financial statements present fairly, in all material respects, the financial position of the Company as of December 31, 2006 and 2007, and the results of its operations and its cash flows for the year ended March 31, 2006, the nine months ended December 31, 2006 and the year ended December 31, 2007, in conformity with accounting principles generally accepted in the United States of America.

Effective April 1, 2006, the Company changed its fiscal year end from March 31 to December 31.

As discussed in Note 2 to the consolidated financial statements, the Company adopted the provisions of SFAS No. 158, "Employers' Accounting for Defined Benefit Pension and Other Postretirement Plans, an amendment of FASB Statements No. 87, 88, 106, and 132(R)," effective December 31, 2006.

/s/ Deloitte & Touche LLP

Cincinnati, Ohio
April 10, 2008

F-9

RHINO ENERGY LLC

CONSOLIDATED STATEMENTS OF FINANCIAL POSITION
AS OF DECEMBER 31, 2006 AND 2007

			December 31,
			2006			2007
ASSETS
CURRENT ASSETS:
	Cash and cash equivalents		$	379,956		$	3,583,395
	Accounts receivable, net of allowance for doubtful accounts ($175,242 and $0 as of December 31, 2006 and 2007, respectively)			30,602,922			41,417,830
	Inventories			10,520,778			7,587,585
	Advance royalties, current portion			618,115			1,205,683
	Prepaid expenses and other			2,796,842			5,686,064

		Total current assets		44,918,613			59,480,557
PROPERTY, PLANT AND EQUIPMENT:
	At cost, including coal properties, mine development and contract costs			245,980,208			289,562,564
	Less accumulated depreciation, depletion and amortization			(48,924,075	)		(77,905,483	)

	Net property, plant and equipment			197,056,133			211,657,081
ADVANCE ROYALTIES, net of current portion				1,706,759			2,392,718
OTHER NON-CURRENT ASSETS				4,512,947			2,461,878

TOTAL			$	248,194,452		$	275,992,234

LIABILITIES AND MEMBERS' EQUITY
CURRENT LIABILITIES:
	Accounts payable		$	12,994,426		$	14,465,527
	Accrued expenses and other			12,819,689			16,850,040
	Current portion of long-term debt			10,009,868			10,161,633
	Current portion of asset retirement obligations			2,928,607			2,582,646
	Current portion of postretirement benefits			97,004			91,785
	Current portion of deferred revenue			1,142,924			580,066

		Total current liabilities		39,992,518			44,731,697
NON-CURRENT LIABILITIES:
	Long-term debt			78,560,612			73,792,083
	Asset retirement obligations			27,239,862			33,804,753
	Other non-current liabilities			2,208,249			1,166,656
	Postretirement benefits			5,305,853			4,656,507

		Total non-current liabilities		113,314,576			113,419,999

		Total liabilities		153,307,094			158,151,695

COMMITMENTS AND CONTINGENCIES (NOTE 9)
MEMBERS' EQUITY:
	Members' investment			32,877,194			23,627,194
	Accumulated other comprehensive income (loss)			(901,040	)		588,376
	Retained earnings			62,911,204			93,624,968

		Total members' equity		94,887,358			117,840,538

TOTAL			$	248,194,452		$	275,992,234

See notes to consolidated financial statements.

F-10

RHINO ENERGY LLC

CONSOLIDATED STATEMENTS OF OPERATIONS
FOR THE YEAR ENDED MARCH 31, 2006, THE NINE MONTHS ENDED DECEMBER 31, 2006
AND THE YEAR ENDED DECEMBER 31, 2007

			Year Ended March 31, 2006			Nine Months Ended December 31, 2006			Year Ended December 31, 2007
REVENUES
	Coal sales		$	351,379,918		$	294,236,719		$	394,078,915
	Freight and handling revenues			6,149,211			2,783,314			4,052,430
	Other revenues			6,430,783			3,818,504			5,320,452

		Total revenues		363,959,912			300,838,537			403,451,797
COSTS AND EXPENSES:
	Cost of operations (exclusive of depreciation, depletion and amortization shown separately below)			291,444,675			238,189,687			318,520,554
	Freight and handling costs			6,342,513			2,768,079			4,020,747
	Depreciation, depletion and amortization			13,744,251			28,471,208			30,749,773
	Selling, general and administrative			17,129,442			18,573,026			15,370,333
	(Gain) loss on retirement of advance royalties			(236,884	)		2,994,555			(115,277	)
	(Gain) loss on sale of assets			(377,219	)		745,818			(944,303	)

		Total costs and expenses		328,046,778			291,742,373			367,601,827
INCOME FROM OPERATIONS				35,913,134			9,096,164			35,849,970
INTEREST AND OTHER INCOME (EXPENSE):
	Interest expense			(4,976,175	)		(6,497,958	)		(5,579,224	)
	Interest income			412,116			311,660			316,710
	Other—net			490,655			272,206			—

		Total interest and other income (expense)		(4,073,404	)		(5,914,092	)		(5,262,514	)
INCOME BEFORE INCOME TAXES				31,839,730			3,182,072			30,587,456
INCOME TAX (BENEFIT) EXPENSE				178,410			124,577			(126,308	)

NET INCOME			$	31,661,320		$	3,057,495		$	30,713,764
Other comprehensive income (loss):
	Change in actuarial gain/(loss) under SFAS No. 158			—			(901,040	)		1,489,416

NET COMPREHENSIVE INCOME			$	31,661,320		$	2,156,455		$	32,203,180

See notes to consolidated financial statements.

F-11

RHINO ENERGY LLC

CONSOLIDATED STATEMENTS OF MEMBERS' EQUITY
FOR THE YEAR ENDED MARCH 31, 2006, THE NINE MONTHS ENDED DECEMBER 31, 2006
AND THE YEAR ENDED DECEMBER 31, 2007

		Members' Investment			Accumulated Other Comprehensive Income (Loss)			Retained Earnings		Total
BALANCE—April 1, 2005		$	32,877,194		$	—		$	28,192,389	$	61,069,583
	Net income		—			—			31,661,320		31,661,320

BALANCE—March 31, 2006			32,877,194			—			59,853,709		92,730,903
	Net income		—			—			3,057,495		3,057,495
	Adoption of SFAS No. 158		—			(901,040	)		—		(901,040	)

BALANCE—December 31, 2006			32,877,194			(901,040	)		62,911,204		94,887,358
	Distributions to members		(9,250,000	)		—			—		(9,250,000	)
	Change in actuarial gain (loss) under SFAS No. 158		—			1,489,416			—		1,489,416
	Net income		—			—			30,713,764		30,713,764

BALANCE—December 31, 2007		$	23,627,194		$	588,376		$	93,624,968	$	117,840,538

See notes to consolidated financial statements.

F-12

RHINO ENERGY LLC

CONSOLIDATED STATEMENTS OF CASH FLOWS
FOR THE YEAR ENDED MARCH 31, 2006, THE NINE MONTHS ENDED DECEMBER 31, 2006
AND THE YEAR ENDED DECEMBER 31, 2007

			Year Ended March 31, 2006			Nine Months Ended December 31, 2006			Year Ended December 31, 2007
CASH FLOWS FROM OPERATING ACTIVITIES:
Net income			$	31,661,320		$	3,057,495		$	30,713,764
Adjustments to reconcile net income to net cash provided by operating activities:
	Depreciation, depletion and amortization			13,744,251			28,471,208			30,749,773
	Accretion on asset retirement obligations			1,685,560			1,412,366			1,756,965
	Accretion on interest-free debt			321,197			255,113			359,817
	Amortization of advance royalties			2,186,767			1,098,453			699,705
	Provision for doubtful accounts			354,449			(282,789	)		(175,242	)
	(Gain) loss on retirement of advance royalties			(236,884	)		2,994,555			(115,277	)
	(Gain) loss on sale of assets			(377,219	)		745,818			(944,303	)
Changes in assets and liabilities:
	Accounts receivable			(15,638,237	)		8,449,841			(10,639,666	)
	Inventories			(2,330,153	)		1,542,261			2,933,193
	Advance royalties			(2,429,220	)		(3,565,157	)		(1,857,955	)
	Prepaid expenses and other assets			(478,784	)		498,588			(1,031,645	)
	Accounts payable			6,801,579			(4,833,180	)		1,471,100
	Accrued expenses and other liabilities			226,883			(3,928,700	)		3,117,347
	Asset retirement obligations			(3,247,648	)		391,351			(5,379,905	)
	Postretirement benefits			648,139			552,256			834,851

		Net cash provided by operating activities		32,892,000			36,859,479			52,492,522

CASH FLOWS FROM INVESTING ACTIVITIES:
	Additions to property, plant, and equipment			(31,485,479	)		(32,701,306	)		(14,598,735	)
	Proceeds from sales of property, plant, and equipment			669,714			364,425			4,482,154
	Principal payments received on note receivable			115,164			2,012,482			293,498
	Changes in restricted cash			1,088,044			1,496,827			(100,006	)
	Acquisitions of coal companies and coal properties			(5,000,000	)		—			(18,174,465	)

		Net cash used in investing activities		(34,612,557	)		(28,827,572	)		(28,097,554	)

CASH FLOWS FROM FINANCING ACTIVITIES:
	Borrowings on line of credit			74,244,218			145,648,104			159,042,000
	Repayments on line of credit			(61,058,062	)		(93,964,924	)		(165,042,000	)
	Proceeds from issuance of long-term debt			1,874,418			2,613,643			1,767,342
	Repayments on long-term debt			(16,181,438	)		(63,437,614	)		(7,708,871	)
	Proceeds from loan payable to related party			88,948			—			—
	Repayments on loan payable to related party			(855,009	)		—			—
	Distributions to members			—			—			(9,250,000	)

		Net cash used in financing activities		(1,886,925	)		(9,140,791	)		(21,191,529	)

NET (DECREASE) INCREASE IN CASH AND CASH EQUIVALENTS				(3,607,482	)		(1,108,884	)		3,203,439
CASH AND CASH EQUIVALENTS—Beginning of period				5,096,322			1,488,840			379,956

CASH AND CASH EQUIVALENTS—End of period			$	1,488,840		$	379,956		$	3,583,395

See notes to consolidated financial statements.

F-13

RHINO ENERGY LLC

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
AS OF DECEMBER 31, 2006 AND 2007
AND FOR THE YEAR ENDED MARCH 31, 2006, THE NINE MONTHS ENDED DECEMBER 31, 2006
AND THE YEAR ENDED DECEMBER 31, 2007

1. ORGANIZATION AND BASIS OF PRESENTATION

Organization—Rhino Energy LLC and its wholly owned subsidiaries (the "Company") produce and market coal from surface and underground mines in Illinois, Kentucky, Ohio, Pennsylvania, West Virginia, and Colorado, with the majority of the Company's sales going to domestic utilities and other coal-related organizations in the United States. The Company was formed in April 2003 and has been built via acquisitions. The Company's direct and indirect wholly owned subsidiaries are as follows: CAM Mining LLC; CAM Kentucky Real Estate LLC; Rhino Northern Holdings LLC; Hopedale Mining LLC; CAM Ohio Real Estate LLC; Springdale Land, LLC; Sands Hill Mining LLC; Clinton Stone LLC; Deane Mining LLC; Reserve Holdings LLC; CAM Coal Trading LLC; Leesville Land, LLC; Taylorville Mining LLC; McClane Canyon Mining LLC; CAM Colorado LLC; CAM BB LLC; CAM Aircraft LLC; Rhino Coalfield Services LLC; Rhino Trucking LLC; Rhino Services LLC; Rhino Energy Services LLC; and Rhino Reclamation Services LLC.

In December 2007, the Company acquired the coal operations of Sands Hill Coal Company, located in Ohio. This acquisition included several surface mines, a stone crusher/screening facility, a coal preparation plant and rights to coal reserves. The Company allocated the purchase price to assets and liabilities acquired based upon an initial determination, which is subject to adjustment, of their respective fair values in accordance with Statement of Financial Accounting Standards No. 141, Business Combinations. As the purchase price of the acquisition was less than the fair value of the net assets acquired, the Company proportionately reduced the related value of its property, plant and equipment at discounted fair value. The recorded value of the assets and (liabilities) were:

Property, plant and equipment		$	28,082,303
Receivables			50,186
Inventory			1,610,817
Accrued expenses			(229,707	)
Accounts payable			(2,393,552	)
Asset retirement obligations			(8,945,582	)

	Net assets acquired (cash consideration paid)	$	18,174,465

Pro forma results of operations that give effect to the Sands Hill acquisition as if it had occurred at the beginning of the period have not been provided, as the Sands Hill acquisition would not have had a significant impact on the Company's results of operations for the year ended December 31, 2007.

Basis of Presentation and Principles of Consolidation—The accompanying consolidated financial statements include the accounts of Rhino Energy LLC and subsidiaries. Intercompany transactions and balances have been eliminated in consolidation.

2. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES AND GENERAL

Company Environment and Risk Factors—The Company, in the course of its business activities, is exposed to a number of risks including: fluctuating market conditions of coal, truck and rail 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

F-14

RHINO ENERGY LLC

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
AS OF DECEMBER 31, 2006 AND 2007
AND FOR THE YEAR ENDED MARCH 31, 2006, THE NINE MONTHS ENDED DECEMBER 31, 2006
AND THE YEAR ENDED DECEMBER 31, 2007 (Continued)

well as the ability of the Company to maintain adequate financing, necessary mining permits and control of sufficient recoverable coal properties. In addition, adverse weather and geological conditions may increase mining costs, sometimes substantially.

Concentrations of Credit Risk—See Note 10 for discussion of major customers. The Company does not require collateral or other security on accounts receivable. The credit risk is controlled through credit approvals and monitoring procedures.

Cash and Cash Equivalents—The Company considers all highly liquid investments purchased with maturities of three months or less to be cash equivalents.

Inventories—Inventories are stated at the lower of cost, based on a three month rolling average, or market. Inventories primarily consist of coal contained in stockpiles.

Advance Royalties—The Company is required, under certain royalty lease agreements, to make minimum royalty payments whether or not mining activity is being performed on the leased property. These minimum payments may be recoupable once mining begins on the leased property. The Company capitalizes the recoupable minimum royalty payments and amortizes the deferred costs once mining activities begin on the units of production method or expenses the deferred costs when the Company has ceased mining or has made a decision not to mine on such property.

Restricted Cash—Included in prepaid expenses and other current assets is restricted cash, representing cash serving as collateral for notes payable and reclamation obligations.

Note Receivable—Included in prepaid expenses and other assets and other non-current assets is a note receivable resulting from a sale of equipment to KAPO Mining, LLC. This note receivable bears interest at a fixed rate of 7%. The Company is due quarterly principal payments of $214,200 and monthly interest payments on the outstanding balance through March 2008. The Company is due a final payment of $1,748,803, plus accrued interest, in April 2008.

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

Asset Impairments—The Company follows Statement of Financial Accounting Standards ("SFAS") No. 144, Accounting for the Impairment or Disposal of Long-Lived Assets, which requires that projected undiscounted future cash flows from use and disposition of assets be compared with the carrying amounts of those assets, when potential impairment is indicated. When the sum of projected undiscounted cash flows is less than the carrying amount, impairment losses are recognized. In determining such impairment losses, discounted cash flows are utilized to determine the fair value of the assets being evaluated. Also, in certain situations, expected mine lives are shortened because of

F-15

RHINO ENERGY LLC

changes to planned operations. When that occurs and it is determined that the mine's underlying costs are not recoverable in the future, reclamation and mine closing obligations are accelerated and the mine closing accrual is increased accordingly. To the extent it is determined that asset carrying values will not be recoverable during a shorter mine life, a provision for such impairment is recognized. During the nine months ended December 31, 2006, the Company wrote off $5,032,089 and $4,954,425 of mineral rights and mine development costs, respectively, due to shortened mine lives. These amounts are included within depreciation, depletion and amortization. There were no impairment losses recorded during the years ended March 31, 2006 and December 31, 2007.

Debt Issuance Costs—Debt issuance costs reflect fees incurred to obtain financing and are amortized (included in interest expense) using the effective interest method, over the life of the related debt. Debt issuance costs are included in other non-current assets.

Asset Retirement Obligations—SFAS No. 143, Accounting for Asset Retirement Obligations, addresses asset retirement obligations that result from the acquisition, construction, or normal operation of long-lived assets. It requires companies to recognize asset retirement obligations at fair value when the liability is incurred or acquired. Upon initial recognition of a liability, that cost should be capitalized as part of the related long-lived asset and allocated to expense over the useful life of the asset. The Company has recorded the asset retirement costs in coal properties.

The Company estimates its future cost requirements for reclamation of land where it has conducted surface and underground mining operations, based on its interpretation of the technical standards of regulations enacted by the U.S. Office of Surface Mining, as well as state regulations. These costs relate to reclaiming the pit and support acreage at surface mines and sealing portals at underground mines. Other reclamation costs are related to refuse and slurry ponds, as well as holding and related termination/exit costs.

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

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RHINO ENERGY LLC

The changes in the Company's asset retirement obligations for the year ended March 31, 2006, the nine months ended December 31, 2006 and the year ended December 31, 2007:

	March 31, 2006			December 31, 2006			December 31, 2007
Balance at beginning of period (including current portion)	$	19,639,536		$	23,306,129		$	30,168,469
Accretion expense		1,685,560			1,412,366			1,756,965
Additions resulting from property additions		3,020,081			1,540,180			9,841,870
Adjustments to the liability from annual recosting and other		2,783,048			6,268,450			(2,578,714	)
Liabilities settled		(3,822,096	)		(2,358,656	)		(2,801,191	)

Balance at end of period		23,306,129			30,168,469			36,387,399
Current portion of asset retirement obligation		1,875,634			2,928,607			2,582,646

Long-term portion of asset retirement obligation	$	21,430,495		$	27,239,862		$	33,804,753

The adjustments to the liability from annual recosting include a change in the discount rate used in the present value calculation of the liability. Changes in the asset retirement obligations for the nine months ended December 31, 2006 and the year ended December 31, 2007 both were calculated with a discount rate 2% lower than the rate used for the year ended March 31, 2006. Other recosting adjustments to the liability are made annually based on inflationary cost increases and changes in the expected operating periods of the mines.

Sales Contract Liability—In connection with certain acquisitions in 2004, the Company acquired certain contracts with sales prices that are below its production cost. The Company recognized a liability for these contracts equal to the present value of the difference between the Company's cost and the contract amount in accordance with SFAS No. 141, Business Combinations. The Company amortizes this liability as sales are made under these sales contracts. Such amortization is included within depreciation, depletion and amortization.

Workers' Compensation and Black Lung Benefits—Certain of the Company's subsidiaries are liable under federal and state laws to pay workers' compensation and coal workers' pneumoconiosis ("black lung") benefits to eligible employees, former employees and their dependents. The Company currently utilizes an insurance program and state workers' compensation fund participation to secure its ongoing workers' compensation and black lung obligations, depending on the location of the operation. Premium expense for workers' compensation and black lung benefits is recognized in the period in which the related insurance coverage is provided. For uninsured claims, the Company maintains an accrual for the estimated cost to settle open claims as well as an estimate of the cost of claims that have been incurred but not reported. These estimates take into account valuations from a third party actuary, current and historical trends and changes in the Company's business and workforce. The accruals for self-insurance could be affected if future occurrences and claims are different from assumptions used and historical trends.

Revenue Recognition—Most of the Company's revenues are generated under long-term coal sales contracts with electric utilities, industrial companies or other coal-related organizations, primarily in the eastern United States. Revenues are recognized on coal sales in accordance with the terms of the sales

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agreement, which is when the coal is shipped to the customer and title has passed. Advance payments received are deferred and recognized in revenue as coal is shipped and title has passed.

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

Other revenues consist of limestone sales, coal handling, royalties, contract mining and rental income. These revenues are recognized in the period earned or when the service is completed.

Rebates—The Company receives rebates from a railroad transportation company for efficiencies obtained at a coal loadout facility. Rebates are based on a contracted rate per ton and are recorded when earned based upon when coal is shipped by the railroad transportation company. Included in revenues is $1,564,841, $959,103 and $400,648 associated with these rebate programs for the year ended March 31, 2006, the nine months ended December 31, 2006 and the year ended December 31, 2007, respectively.

Derivative Financial Instruments—During the year ended March 31, 2006 and the nine months ended December 31, 2006, the Company used futures contracts to manage the risk of fluctuations in the sales price of coal. The Company did not use derivative financial instruments for trading or speculative purposes. The Company designated the futures contracts as cash flow hedges and recorded the derivative financial instruments as either assets or liabilities, at fair value, in accordance with SFAS No. 133, Accounting for Derivative Instruments and Hedging Activities, as amended by SFAS No. 138, Accounting for Certain Derivative Instruments and Certain Hedging Activities and SFAS No. 149, Amendment on Statement 133 on Derivative Instruments and Hedging Activities. Changes in fair value are recorded as adjustments to the assets and liabilities being hedged in accumulated other comprehensive income, or in current earnings, depending on whether the derivative is designated and qualifies for hedge accounting, the type of transactions represented and the effectiveness of the hedge.

The Company did not enter into any new futures contracts during the nine months ended December 31, 2006 and the year ended December 31, 2007. At December 31, 2006 and 2007, the Company had no outstanding futures contracts.

In February 2008, the Company entered into futures contracts to sell 240,000 tons of coal at a weighted average price of $83.25 per ton.

Income taxes—The Company is considered as a partnership for income tax purposes. Accordingly, the members report the Company's taxable income or loss on their tax returns. The provisions for income tax consisted of state income taxes for the year ended March 31, 2006 and for the nine months ended December 31, 2006. This provision was a result of the state of Kentucky instituting a law effective January 1, 2005 that required partnerships to pay state income taxes. This law was rescinded on January 1, 2007, resulting in an income tax benefit for the year ended December 31, 2007.

The provision for income taxes consists of state income taxes for the year ended March 31, 2006 and the nine months ended December 31, 2006. This provision is a result of the state of Kentucky instituting a law effective January 1, 2005, that requires partnerships to pay state and local income taxes. This law was rescinded on January 1, 2007, resulting in an income tax benefit for the year ended December 31, 2007.

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RHINO ENERGY LLC

Loss Contingencies—In accordance with SFAS No. 5, Accounting for Contingencies, the Company records any loss contingencies at such time that an unfavorable outcome becomes probable and the amount can be reasonably estimated. When the reasonable estimate is a range, the recorded loss is the best estimate within the range. If no amount in the range is a better estimate than any other amount, the minimum amount of the range is recorded. The Company discloses information concerning loss contingencies for which an unfavorable outcome is more than remote. See Note 9, "Commitments and Contingencies," for a discussion of legal matters.

Management's Use of Estimates—The preparation of consolidated financial statements in conformity with accounting principles generally accepted in the United States of America requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities at the date of the consolidated financial statements and the reported amounts of revenues and expenses during the reporting period. Actual results could differ from those estimates.

Recent Accounting Pronouncements—In June 2006, the Financial Accounting Standards Board ("FASB") issued Financial Interpretation No. 48, Accounting for Uncertainty in Income Taxes, an interpretation of FASB Statement No. 109 ("FIN 48"). This interpretation clarifies the accounting for uncertainty in income taxes recognized in an enterprise's financial statements in accordance with FASB Statement No. 109, Accounting for Income Taxes. Since the Company is not a taxable entity for federal and state income tax purposes, its adoption of FIN 48 on January 1, 2007 did not have a material impact on its consolidated financial statements.

In September 2006, the FASB issued SFAS No. 157, Fair Value Measures ("SFAS No. 157"), which establishes a framework for measuring fair value and expands disclosures about fair value measurements. Pursuant to FASB Financial Staff Position 157-2, the FASB issued a partial deferral of the implementation of SFAS No. 157 as it relates to all non-financial assets and liabilities where fair value is not already the required measurement attribute by other accounting standards. The remainder of SFAS No. 157 was effective for the Company on January 1, 2008. The adoption of SFAS No. 157 did not have a material impact on the Company's financial position, results of operations or cash flows.

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instruments. For the Company, the election to apply the standard and measure certain financial instruments at fair value would be effective prospectively beginning January 1, 2008. The adoption of SFAS No. 159 did not have a material impact on the Company's financial position, results of operations or cash flows.

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

3. PREPAID EXPENSES AND OTHER CURRENT ASSETS

Prepaid expenses and other current assets as of December 31, 2006 and 2007 consisted of the following:

	December 31, 2006		December 31, 2007
Note receivable	$	856,800	$	2,091,285
Restricted cash		550,928		663,960
Deferred offering costs		—		51,779
Other prepaid expenses		174,068		444,459
Prepaid insurance		714,466		1,444,504
Prepaid leases		169,163		182,743
Supply inventory		—		111,249
Deposits		78,774		45,300
Rebates receivable		252,643		650,785

Total	$	2,796,842	$	5,686,064

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RHINO ENERGY LLC

4. PROPERTY, PLANT AND EQUIPMENT

Property, plant and equipment, including coal properties and mine development and construction costs, as of December 31, 2006 and 2007 are summarized by major classification as follows:

		Useful Lives	December 31, 2006			December 31, 2007
Land and land improvements			$	14,021,744		$	17,185,007
Mining and other equipment and related facilities		2 - 20 Years		111,555,425			143,124,537
Mine development costs		1 - 15 Years		32,614,869			35,571,195
Coal properties		1 - 15 Years		79,670,199			92,688,622
Construction work in process				8,117,971			993,203

	Total			245,980,208			289,562,564
Less accumulated depreciation, depletion and amortization				(48,924,075	)		(77,905,483	)

	Net		$	197,056,133		$	211,657,081

Depreciation expense for mining and other equipment and related facilities for the year ended March 31, 2006, the nine months ended December 31, 2006 and the year ended December 31, 2007 was $12,069,063, $12,770,013 and $20,960,235, respectively. Depletion expense for coal properties for the year ended March 31, 2006, the nine months ended December 31, 2006 and the year ended December 31, 2007 was $3,117,616, $7,461,467 and $3,611,530, respectively. Amortization expense for mine development costs for the year ended March 31, 2006, the nine months ended December 31, 2006 and the year ended December 31, 2007 was $2,525,160, $8,036,775 and $4,211,449, respectively.

5. OTHER NON-CURRENT ASSETS

Other non-current assets as of December 31, 2006 and 2007 consisted of the following:

		December 31, 2006		December 31, 2007
Note receivable		$	2,732,593	$	1,204,610
Deposits and other			591,826		285,715
Debt issuance costs—net			1,138,326		911,672
Deferred expenses			37,176		59,881
Other			13,026		—

	Total	$	4,512,947	$	2,461,878

Debt issuance costs were $2,207,085 and $2,218,131 as of December 31, 2006 and 2007, respectively. Accumulated amortization of debt issuance costs were $1,068,759 and $1,306,459 as of December 31, 2006 and 2007, respectively.

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RHINO ENERGY LLC

6. ACCRUED EXPENSES AND OTHER CURRENT LIABILITIES

Accrued expenses and other current liabilities as of December 31, 2006 and 2007 consisted of the following:

	December 31, 2006		December 31, 2007
Payroll, bonus and vacation expense	$	2,577,799	$	3,605,125
Non income taxes		3,527,320		3,064,416
Royalty expenses		2,922,277		2,702,810
Accrued interest		649,919		376,316
Health claims		1,380,858		1,961,410
Coal lease payable		413,000		413,000
Accrued income taxes		296,950		24,279
Workers' compensation and pneumoconiosis		243,518		1,566,298
Other		828,048		3,136,386

Total	$	12,819,689	$	16,850,040

7. DEBT

Debt as of December 31, 2006 and 2007 consisted of the following:

		December 31, 2006			December 31, 2007
Revolving line of credit with PNC Bank, N.A.		$	75,000,000		$	69,000,000
Note payable to H&L Construction Co., Inc.			7,412,003			7,135,638
Capital lease obligation with Applied Financial			1,046,272			732,777
Capital lease obligations with National City Bank			4,385,503			—
Note payable to National City Bank			—			1,093,300
Note payable to Huntington National Bank			—			2,945,375
Other notes payable			726,702			3,046,626

	Total		88,570,480			83,953,716
Less current portion of long-term debt			(10,009,868	)		(10,161,633	)

Long term debt		$	78,560,612		$	73,792,083

Revolving line of credit with PNC Bank, N.A.—Borrowings under the line of credit bear interest which varies depending upon the grouping of the borrowings within the line of credit. At December 31, 2007 the Company had borrowed $68,000,000 at a variable interest rate of LIBOR plus 1.00% (5.83% at December 31, 2007) and $1,000,000 at a variable interest rate of Prime (7.25% at December 31, 2007). In addition, the Company had outstanding letters of credit of $18,388,530 at a fixed interest rate of 1.15% at December 31, 2007. The maximum amount available on the line of credit with PNC is $125,000,000. At December 31, 2007, the Company had not used $37,611,470 of the borrowing availability. As part of the agreement, the Company is required to pay a commitment fee of 0.25% on

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RHINO ENERGY LLC

the unused portion of the borrowing availability. Borrowings on the line of credit are collateralized by all the unsecured assets of the Company.

In February 2008, the Company amended the credit agreement with PNC and increased the maximum availability to $200,000,000. The amended credit agreement is to expire in February 2013.

The revolving credit commitment requires the Company to maintain certain minimum financial ratios and contains certain restrictive provisions, including among others, restrictions on making loans, investments and advances, incurring additional indebtedness, guaranteeing indebtedness, creating liens, and selling or assigning stock. The Company was in compliance with all restrictive provisions as of December 31, 2007.

Note payable to H&L Construction Co., Inc.—The note payable to H&L Construction Co., Inc. is a non-interest bearing note. The Company has recorded a discount for imputed interest at a rate of 6.5% on this note. The Company is amortizing this discount over the life of the note using the effective interest method. The note payable matures in April 2009. The note is secured by mineral rights purchased by the Company from H&L Construction Co., Inc. with a carrying amount of $13,654,234 at December 31, 2007.

Capital Lease Obligation with Applied Financial—Borrowings under the capital lease with Applied Financial are to be paid back in 48 equal installments of $30,104, with final payment due in March 2010.

Capital Lease Obligations with National City Bank—Borrowings under the two capital leases with National City Bank are to be paid back in 48 equal installments of $74,586 and $48,960, with final payments due in April 2010. These notes were fully paid during 2007.

Note payable to National City Bank—Borrowing under the note payable to National City Bank bear interest at a variable rate of LIBOR plus 1.35% (6.18% at December 31, 2007) This note is payable in monthly principal and interest installments and matures in February 2010.

Note payable to Huntington National Bank—Borrowings under the note payable to Huntington National Bank bear interest at a fixed rate of 6.80%. This note is payable in monthly principal and interest installments and matures in May 2010.

Principal payments on long-term debt due subsequent to December 31, 2007, are as follows:

2008	$	10,161,633
2009		2,070,776
2010		649,810
2011		—
2012		69,000,000
Thereafter		2,393,552

Total principal payments		84,275,771
Less imputed interest on interest free notes payable		(322,055	)

Total debt	$	83,953,716

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RHINO ENERGY LLC

8. EMPLOYEE BENEFITS

Postretirement Plan—In conjunction with the acquisition of the coal operations of American Electric Power on April 16, 2004, the Company acquired a postretirement benefit plan providing healthcare to eligible employees. The Company has no other postretirement plans.

As discussed in Note 2, the Company adopted SFAS No. 158 on December 31, 2006 on the required prospective basis.

Summaries of the changes in benefit obligations and funded status of the plan as of the measurement dates of March 31, 2006 and December 31, 2006 and 2007 are as follows:

		Year Ended March 31, 2006			Nine Months Ended December 31, 2006			Year Ended December 31, 2007
Benefit obligation at beginning of period		$	3,442,537		$	4,115,559		$	5,402,857
Changes in benefit obligations:
	Service costs		448,800			387,147			535,428
	Interest cost		199,339			178,301			292,199
	Benefits paid		—			(13,192	)		(15,693	)
	Actuarial loss (gain)		24,883			735,042			(1,476,499	)

Benefit obligation at end of period		$	4,115,559		$	5,402,857		$	4,748,292

Fair value of plan assets at end of period		$	—		$	—		$	—

Funded status		$	(4,115,559	)	$	(5,402,857	)	$	(4,748,292	)

		Year Ended March 31, 2006			Nine Months Ended December 31, 2006			Year Ended December 31, 2007
Calculation of net amount recognized:
	Funded status at end of period	$	(4,115,559	)	$	(5,402,857	)	$	(4,748,292	)
	Unrecognized actuarial loss		165,998			n/a			n/a

Net amount recognized		$	(3,949,561	)	$	(5,402,857	)	$	(4,748,292	)

		Year Ended March 31, 2006			Nine Months Ended December 31, 2006			Year Ended December 31, 2007
Classification of net amount recognized:
	Current liability—postretirement benefits	$	(64,025	)	$	(97,004	)	$	(91,785	)
	Non-current liability—postretirement benefits		(3,885,536	)		(5,305,853	)		(4,656,507	)

Net amount recognized		$	(3,949,561	)	$	(5,402,857	)	$	(4,748,292	)

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RHINO ENERGY LLC

		Year Ended March 31, 2006	Nine Months Ended December 31, 2006			Year Ended December 31, 2007
Amount recognized in accumulated other comprehensive income (loss):
	Net actuarial gain (loss)	n/a	$	(901,040	)	$	588,376

Weighted Average Assumptions		Year Ended March 31, 2006		Nine Months Ended December 31, 2006		Year Ended December 31, 2007
Discount rate		6.00	%	5.60	%	6.25	%
Expected return on plan assets		n/a		n/a		n/a

		Year Ended March 31, 2006		Nine Months Ended December 31, 2006		Year Ended December 31, 2007
Net periodic benefit cost:
	Service costs	$	448,800	$	387,147	$	535,428
	Interest cost		199,339		178,301		293,199

Benefit cost		$	648,139	$	565,448	$	828,627

Actual contributions from January 1, 2007 through December 31, 2007:	$	15,693
Expected benefit payments:
Period
2008	$	91,785
2009		161,882
2010		223,558
2011		326,161
2012		450,218
2013-2017		4,311,257

For measurement purposes, a 9.0% annual rate of increase in the per capita cost of covered health care benefits was assumed, gradually decreasing to 5.0% in 2016 and remaining level thereafter.

Net periodic benefit cost is determined using the assumptions as of the beginning of the year, and the funded status is determined using the assumptions as of the end of the year. Effective June 1, 2007, employees hired by the Company are not eligible for benefits under the plan.

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RHINO ENERGY LLC

The expense and liability estimates can fluctuate by significant amounts based upon the assumptions used. As of December 31, 2007, a one-percentage-point change in assumed health care cost trend rates would have the following effects:

		One-Percentage Point Increase			One-Percentage Point Decrease
Effect on total service and interest cost components		$	47,037		$	(42,046	)
Effect on postretirement benefit obligation		$	409,396		$	(371,336	)

401(k) Plans—The Company and certain subsidiaries sponsor defined contribution savings plans for all employees. Under one defined contribution savings plan, the Company matches voluntary contributions of participants up to a maximum contribution based upon a percentage of a participant's salary with an additional matching contribution possible at the Company's discretion. The Company made discretionary contributions of $732,936, $522,960 and $674,596 for the year ended March 31, 2006, the nine months ended December 31, 2006 and the year ended December 31, 2007, respectively. Under the Company's remaining defined contribution savings plans, any contributions made by the Company are based on the Company's discretion. The expense under these plans for the year ended March 31, 2006, the nine months ended December 31, 2006 and the year ended December 31, 2007, was approximately $1,419,000, $1,043,000 and 1,261,600, respectively.

9. COMMITMENTS AND CONTINGENCIES

Coal Sales Contracts and Contingencies—As of December 31, 2007, the Company had commitments under sales contracts to deliver annually scheduled base quantities of 6.9 million, 4.5 million and 2.2 million tons of coal to 23 customers in 2008, 12 customers in 2009, and 4 customers in 2010, respectively. Certain of the contracts have sales price adjustment provisions, subject to certain limitations and adjustments, based on a variety of factors and indices.

Purchase Commitments—As of December 31, 2007, the Company had 8.1 million gallons remaining on a commitment to purchase diesel fuel at fixed prices ranging from $1.90 to $2.81 per gallon through May 2009.

Leases—The Company leases various mining, transportation and other equipment under operating leases. Lease expense for the year ended March 31, 2006, the nine months ended December 31, 2006 and the year ended December 31, 2007 was approximately $8,099,000, $8,469,000 and $10,423,000, respectively.

The Company also leases coal reserves under agreements that call for royalties to be paid as the coal is mined. Total royalty expense for the year ended March 31, 2006, the nine months ended December 31, 2006 and the year ended December 31, 2007 was approximately $20,699,000, $13,882,000 and $20,518,000, respectively.

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RHINO ENERGY LLC

Approximate future minimum lease and royalty payments (not including advance royalties already paid and recorded as assets in the accompanying statements of financial position) are as follows:

Years Ending December 31,	Royalties		Leases
2008	$	2,315,000	$	7,788,000
2009		1,902,000		6,128,000
2010		1,902,000		1,135,000
2011		1,526,000		1,123,000
2012		1,402,000		1,127,000
Thereafter		7,010,000		6,143,000

Total minimum royalty and lease payments	$	16,057,000	$	23,444,000

Environmental Matters—Based upon current knowledge, the Company believes that it is in compliance with environmental laws and regulations as currently promulgated. However, the exact nature of environmental control problems, if any, which the Company may encounter in the future cannot be predicted, primarily because of the increasing number, complexity and changing character of environmental requirements that may be enacted by federal and state authorities.

Legal Matters—The Company is involved in various legal proceedings arising in the ordinary course of business. In the opinion of management, the Company is not party to any pending litigation that is likely to have a material adverse effect on the financial condition, results of operations or cash flows of the Company. Management of the Company is not aware of any significant legal or governmental proceedings against or contemplated to be brought against the Company. In addition, the Company maintains insurance policies with insurers in amounts and with coverage and deductibles which management believes are reasonable and prudent.

Guarantees/Indemnifications and Financial Instruments with Off-Balance Sheet Risk —In the normal course of business, the Company is a party to certain guarantees and financial instruments with off-balance sheet risk, such as bank letters of credit and performance or surety bonds. No liabilities related to these arrangements are reflected in the Company's consolidated statements of financial position. Management does not expect any material losses to result from these guarantees or off-balance sheet financial instruments. The amount of bank letters of credit outstanding with PNC as of December 31, 2007 was $18,388,530. The bank letters of credit outstanding with PNC reduce the Company's borrowing capacity on its line of credit with PNC. In addition, the Company has outstanding surety bonds with third parties of $49,432,535 as of December 31, 2007, to secure reclamation and other performance commitments.

The line of credit with PNC is fully and unconditionally, jointly and severally guaranteed by the Company and substantially all of its wholly owned subsidiaries. Borrowings on the line of credit with PNC are collateralized by the unsecured assets of the Company and substantially all of its wholly owned subsidiaries. See Note 7 for a more complete discussion of the Company's debt obligations.

The Company is owned by a collection of investment funds managed by Wexford Capital LLC ("Wexford"). These funds fully and unconditionally guarantee the Company's obligations under its outstanding surety bonds with third parties to secure reclamation and other performance commitments.

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RHINO ENERGY LLC

Employment Agreements—The Company has employment agreements with key executive officers which expire between December 2008 and May 2011. In addition to a base salary, the agreements provide for bonuses based on net income. No maximum compensation limit exists. Total salary and bonus expenses of $2,111,712, $3,263,190 and $4,385,735 were recognized under the employment agreements for the year ended March 31, 2006, the nine months ended December 31, 2006 and the year ended December 31, 2007, respectively.

10. MAJOR CUSTOMERS

The Company had receivables or revenues from the following major customers that in each period equaled or exceeded 10% of total revenues:

	March 31, 2006 Receivable Balance		Year Ended March 31, 2006 Sales		December 31, 2006 Receivable Balance		Nine Months Ended December 31, 2006 Sales		December 31, 2007 Receivable Balance		Year Ended December 31, 2007 Sales
Customer A		n/a		n/a	$	6,980,467	$	59,270,453	$	6,112,034	$	97,930,807
Customer B	$	3,654,547	$	61,612,564		n/a		n/a	$	1,805,892	$	57,110,321
Customer C		n/a		n/a		n/a		n/a	$	5,662,044	$	68,011,968
Customer D		n/a		n/a	$	6,299,003	$	71,709,624	$	3,597,077	$	52,746,859

11. FAIR VALUE OF FINANCIAL INSTRUMENTS

The book values of cash and cash equivalents, accounts receivable and accounts payable are considered to be representative of their respective fair values because of the immediate short-term maturity of these financial instruments. The carrying value of the Company's debt instruments and notes receivable approximate fair value since effective rates for these instruments are comparable to market at year-end.

12. RELATED PARTY TRANSACTIONS

From time to time, employees from Wexford perform legal, consulting, and advisory services to the Company. The Company incurred expenses of approximately $70,186, $146,254 and $165,719 for year ended March 31, 2006, the nine months ended December 31, 2006 and the year ended December 31, 2007, respectively, for legal, consulting, and advisory services performed by Wexford.

During the year ended December 31, 2007, the Company made cash distributions to members of $9,250,000.

During the year ended March 31, 2006, the Company had borrowings under a note payable to Callidus Investors, an equity fund managed by Wexford. The Company had no outstanding borrowings under this note as of December 31, 2006 and 2007. The Company made payments of $855,000 on notes payable for the year ended March 31, 2006. The Company recorded interest expense of $75,755 for the year ended March 31, 2006.

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13. SUPPLEMENTAL DISCLOSURES OF CASH FLOW INFORMATION

Cash payments for interest were $4,654,978, $5,416,373 and $4,958,231 for the year ended March 31, 2006, the nine months ended December 31, 2006 and the year ended December 31, 2007, respectively.

The statement of cash flows for the year ended March 31, 2006, is exclusive of (1) $29,887,861 property additions financed through long-term debt borrowings and other assumed liabilities,; and (2) $5,228,681 of non-cash additions to asset retirement obligations and mineral rights.

The statement of cash flows for the nine months ended December 31, 2006, is exclusive of (1) $9,692,093 of property additions financed through long-term debt borrowings and other assumed liabilities; and (2) $5,058,623 of non-cash additions to asset retirement obligations and mineral rights.

The statement of cash flows for the year ended December 31, 2007, is exclusive of (1) $6,964,948 of property additions financed through long-term debt borrowings and other assumed liabilities; and (2) $9,841,870 of non-cash additions to asset retirement obligations and mineral rights.

14. SEGMENT INFORMATION

The Company produces and markets coal from surface and underground mines in Kentucky, West Virginia, Ohio and Colorado. The Company sells primarily to electric utilities in the United States. The Company has two reportable business segments: Central Appalachia (comprised of both surface and underground mines located in eastern Kentucky and southern West Virginia) and Northern Appalachia (comprised of underground mines located in Ohio). The Other segment includes the mines located in Colorado and southern Ohio that do not meet the aggregation criteria and that do not exceed the quantitative thresholds requiring separate disclosure as a reportable segment. The Company has not provided disclosure of total expenditures by segment for long-lived assets, as the Company does not maintain discrete financial information concerning segment expenditures for long-lived assets, and accordingly such information is not provided to the Company's chief operating decision maker. The Other segment includes the Company's Colorado, Illinois, southern Ohio and other ancillary businesses, NYMEX coal trading activities (the year ended March 31, 2006 and the nine months ended December 31, 2006 only), and corporate overhead expenses.

Reportable segment financial condition and results of operations as of and for the year ended March 31, 2006 are as follows:

	Central Appalachia		Northern Appalachia		Other			Total Segments
Total assets	$	128,233,238	$	25,184,758	$	93,341,314		$	246,759,310
Total revenues	$	307,138,637	$	48,954,497	$	7,866,778		$	363,959,912
Depreciation, depletion and amortization	$	10,966,108	$	2,503,562	$	274,581		$	13,744,251
Interest expense	$	4,184,664	$	636,179	$	155,332		$	4,976,175
Net income (loss)	$	29,022,453	$	2,672,537	$	(33,669	)	$	31,661,320

The Other segment includes revenue, depreciation, depletion and amortization, interest and net income from the Company's Colorado operation and other ancillary businesses. Total assets in the Other segment consists of intercompany receivables and payables between the Company and its subsidiaries, and assets related to the Company's Colorado operation and other ancillary businesses.

F-29

RHINO ENERGY LLC

Reportable segment financial condition and results of operations as of and for the nine months ended December 31, 2006 are as follows:

	Central Appalachia			Northern Appalachia		Other			Total Segments
Total assets	$	117,249,310		$	29,770,697	$	101,174,445		$	248,194,452
Total revenues	$	247,810,356		$	45,461,601	$	7,566,580		$	300,838,537
Depreciation, depletion and amortization	$	24,628,214		$	3,122,627	$	720,367		$	28,471,208
Interest expense	$	4,568,804		$	906,115	$	1,023,039		$	6,497,958
Net income (loss)	$	(227,016	)	$	5,212,089	$	(1,927,578	)	$	3,057,495

Reportable segment financial condition and results of operations as of and for the year ended December 31, 2007 are as follows:

	Central Appalachia		Northern Appalachia		Other			Total Segments
Total assets	$	127,547,348	$	28,963,615	$	119,481,271		$	275,992,234
Total revenues	$	339,592,714	$	53,420,917	$	10,438,166		$	403,451,797
Depreciation, depletion and amortization	$	24,488,240	$	4,162,778	$	2,098,755		$	30,749,773
Interest expense	$	4,165,825	$	712,527	$	700,872		$	5,579,224
Net income (loss)	$	23,091,612	$	9,038,762	$	(1,416,613	)	$	30,713,764

The Other segment includes revenue (including limestone revenues of $207,275), depreciation, depletion and amortization, interest and net income from the Company's operations in Colorado, Illinois and southern Ohio, and other ancillary businesses. Total assets in the Other segment consists of intercompany receivables and payables between the Company and its subsidiaries, and assets related to the Company's operations in Colorado and southern Ohio, and other ancillary businesses.

15. CHANGE IN FISCAL YEAR (UNAUDITED)

Effective April 1, 2006, the Company changed its fiscal year end from March 31 to December 31. Condensed consolidated financial information as of and for the nine months ended December 31, 2005 and 2006 is as follows:

	As of and For the Nine Months Ended December 31,
	2005		2006
Total assets	$	222,595,575	$	248,194,452
Total liabilities	$	139,573,344	$	153,307,094
Total revenues	$	255,329,872	$	300,838,537
Total costs and expenses	$	230,118,248	$	291,742,373

F-30

RHINO ENERGY LLC

Net income	$	21,952,648		$	3,057,495
Cash provided by operating activities	$	33,145,694		$	36,859,479
Cash (used) in investing activities	$	(53,507,347	)	$	(28,827,572	)
Cash provided by (used in) financing activities	$	15,426,270		$	(9,140,791	)

16. SELECTED QUARTERLY FINANCIAL DATA (UNAUDITED)

A summary of our quarterly operating results for the nine months ended December 31, 2006 and the year ended 2007 is as follows:

	Quarter Ended
	June 30, 2006		September 30, 2006		December 31, 2006
Total revenues	$	104,757,843	$	100,627,081	$	95,453,613
Income (loss) from operations	$	8,317,649	$	7,827,049	$	(7,048,534	)
Net income (loss)	$	6,854,623	$	5,489,087	$	(9,286,215	)

	Quarter Ended
	March 31, 2007		June 30, 2007		September 30, 2007		December 31, 2007
Total revenues	$	101,551,710	$	91,949,329	$	100,311,791	$	109,638,967
Income from operations	$	11,141,725	$	8,444,387	$	10,415,680	$	5,848,178
Net income	$	9,495,000	$	7,274,296	$	9,101,359	$	4,843,109

17. SUBSEQUENT EVENT

In February 2008, the Company acquired the coal operations of Deane mining complex, located in Kentucky. This acquisition included several underground mines, surface property, a preparation plant and a unit train load-out. The Company allocated the purchase price to assets and liabilities acquired based upon an initial determination, which is subject to adjustment, of their respective fair values in accordance with Statement of Financial Accounting Standards No. 141, Business Combinations. The recorded value of the assets and (liabilities) were:

Property, plant and equipment		$	31,493,404
Property taxes			(5,014	)
Asset retirement obligations			(16,823,731	)

	Net assets acquired (cash consideration paid)	$	14,664,659

F-31

REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

To the Partners of Rhino Resource Partners, L.P.
Lexington, Kentucky

We have audited the accompanying statements of financial position of Rhino Resource Partners, L.P. (the "Partnership") as of December 31, 2006 and 2007. These financial statements are the responsibility of the Partnership's management. Our responsibility is to express an opinion on these financial statements based on our audit.

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

In our opinion, such statements of financial position present fairly, in all material respects, the financial position of the Partnership at December 31, 2006 and 2007, in conformity with accounting principles generally accepted in the United States of America.

/s/ Deloitte & Touche LLP

Cincinnati, Ohio
April 10, 2008

F-32

RHINO RESOURCE PARTNERS, L.P.

STATEMENTS OF FINANCIAL POSITION
AS OF DECEMBER 31, 2006 AND 2007

		December 31, 2006			December 31, 2007
Assets		$	—		$	—

Liabilities		$	—		$	—

Partners' equity
	Limited partner's equity		980			980
	General partner's equity		20			20
	Receivable from partners		(1,000	)		(1,000	)

Total partners' equity			—			—

Total liabilities and partners' equity		$	—		$	—

See notes to statements of financial position.

F-33

RHINO RESOURCE PARTNERS, L.P.

NOTE TO THE STATEMENTS OF FINANCIAL POSITION

1. ORGANIZATION AND OPERATIONS

Rhino Resource Partners, L.P. (the "Partnership") is a Delaware limited partnership formed on January 11, 2006 to acquire the assets of Rhino Energy LLC, an entity engaged primarily in the mining and sale of coal. The Partnership intends to operate the acquired assets through a wholly owned operating company.

The Partnership intends to offer 5,000,000 common units, representing limited partner interests, pursuant to a public offering. In addition, the Partnership will issue 27,925,200 common units and 3,741,500 subordinated units, representing additional limited partner interests, to certain investment funds managed by Wexford Capital LLC ("Wexford Funds"). Rhino GP LLC, the general partner of the Partnership, will maintain its 2% general partner interest in the Partnership. The Partnership will issue to the general partner the incentive distribution rights, which entitle the holder to increasing percentages, up to a maximum of 10%, of the cash the Partnership distributes in excess of $0.425 per unit per quarter. Certain executive officers and directors of Rhino GP LLC are principals of Wexford Capital LLC.

Rhino GP LLC, as the general partner, has committed to contribute $20 to the Partnership. Rhino Energy Holdings LLC, an entity owned by Wexford Funds, has committed to contribute $980 to the Partnership. These contributions receivable are reflected as a reduction to partners' equity.

The Partnership had no operations during the period from January 11, 2006 (date of formation) to December 31, 2006 or for the year ended December 31, 2007.

2. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

Recent Accounting Pronouncements—In June 2006, the Financial Accounting Standards Board ("FASB") issued Financial Interpretation No. 48, Accounting for Uncertainty in Income Taxes, an interpretation of FASB Statement No. 109 ("FIN 48"). This interpretation clarifies the accounting for uncertainty in income taxes recognized in an enterprise's financial statements in accordance with FASB Statement No. 109, Accounting for Income Taxes. Since the Partnership is not a taxable entity for federal and state income tax purposes, its adoption of FIN 48 on January 1, 2007 did not have a material impact on its statements of financial position.

Emerging Issues Task Force Issue No. 03-06, Participating Securities and the Two-Class Method under FASB Statement No. 128 ("EITF 03-06"), addresses the computation of earnings per share by entities that have issued securities other than common stock that contractually entitle the holder to participate in dividends and earnings of the entity. EITF 03-06 provides that the limited partner's interest in net income is to be calculated based on the amount that would be allocated to the limited partner if all the net income for the period were distributed, and not on the basis of actual cash distributions for the period. The application of EITF 03-06 may have an impact on earnings per limited partner unit in future periods if there are material differences between net income and actual cash distributions or if other participating securities are issued.

In February 2008, the FASB Emerging Issues Task Force issued EITF Issue No. 07-04, Application of the Two-Class Method under FASB Statement No. 128, Earnings per Share, to Master Limited Partnerships ("EITF 07-04"). EITF 07-04 specifies when a master limited partnership becomes contractually obligated to make cash distributions to general partners, limited partners and holders of incentive distribution rights, for purposes of calculating earnings per unit. EITF 07-04 is effective for fiscal years beginning after December 15, 2008. The Partnership is currently evaluating the effect that the adoption of EITF will have on the Partnership's net earnings per unit.

F-34

REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

To the Members of Rhino GP LLC
Lexington, Kentucky

We have audited the accompanying statements of financial position of Rhino GP LLC (the "Company") as of December 31, 2006 and 2007. These financial statements are the responsibility of the Company's management. Our responsibility is to express an opinion on these financial statements based on our audit.

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

In our opinion, such statements of financial position present fairly, in all material respects, the financial position of the Company at December 31, 2006 and 2007, in conformity with accounting principles generally accepted in the United States of America.

/s/ Deloitte & Touche LLP

Cincinnati, Ohio
April 10, 2008

F-35

RHINO GP LLC

STATEMENTS OF FINANCIAL POSITION
AS OF DECEMBER 31, 2006 AND 2007

		December 31, 2006			December 31, 2007
Assets		$	—		$	—

Liabilities		$	—		$	—

Members' equity
	Members' equity		1,000			1,000
	Receivable from members		(1,000	)		(1,000	)

Total members' equity		$	—		$	—

Total liabilities and members' equity		$	—		$	—

See notes to statements of financial position.

F-36

RHINO GP LLC

NOTES TO THE STATEMENTS OF FINANCIAL POSITION

1. ORGANIZATION AND OPERATIONS

Rhino GP LLC is a Delaware limited liability company (the "Company") formed on January 11, 2006 for the purpose of becoming the general partner of Rhino Resource Partners, L.P. (the "Partnership"). Principals of Wexford Capital LLC have committed to contribute $1,000 to the Company. This contribution receivable is reflected as a reduction to members' equity.

The Company had no operations during the period from January 11, 2006 (date of formation) to December 31, 2006 or for the year ended December 31, 2007.

2. EMPLOYEE BENEFITS

Long-Term Incentive Plan—Upon the consummation of the initial public offering of the common units of the Partnership, the Company will adopt the Rhino Resource Partners, L.P. Long-Term Incentive Plan for employees, consultants and directors of the Company and affiliates who perform services for the Partnership. The long-term incentive plan will consist of six components: restricted units, phantom units, bonus units, unit options, unit appreciation rights and distribution equivalent rights. The long-term incentive plan will limit the number of units that may be delivered pursuant to awards to 10% of the outstanding units on the effective date of the initial public offering of the Partnership's units. Units withheld to satisfy exercise prices or tax withholding obligations are available for delivery pursuant to other awards. The plan will be administered by the board of directors of the Company or a committee thereof, which is referred to as the plan administrator.

3. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES AND GENERAL

Recent Accounting Pronouncements—In June 2006 FASB issued Financial Interpretation No. 48, Accounting for Uncertainty in Income Taxes, an interpretation of FASB Statement No. 109 ("FIN 48"). This interpretation clarifies the accounting for uncertainty in income taxes recognized in an enterprise's financial statements in accordance with FASB Statement No. 109, Accounting for Income Taxes. Since the Company is not a taxable entity for federal and state income tax purposes, its adoption of FIN 48 on January 1, 2007 did not have a material impact on its statements of financial position.

F-37

APPENDIX A

Form of First Amended and Restated Agreement
of Limited Partnership of Rhino Resource Partners, L.P.

A-1

APPENDIX B

Glossary of Terms

adjusted operating surplus: For any period, operating surplus generated during that period is adjusted to:

(a)

decrease operating surplus by:

(1): any net increase in working capital borrowings with respect to that period; and
(2): any net decrease in cash reserves for operating expenditures made with respect to that period not relating to an operating expenditure made with respect to that period; and

(b)

increase operating surplus by:

(1): any net decrease in working capital borrowings with respect to that period; and
(2): any net increase in cash reserves for operating expenditures made with respect to that period required by any debt instrument for the repayment of principal, interest or premium.

Adjusted operating surplus does not include that portion of operating surplus included in clauses (a)(1) and (a)(2) of the definition of operating surplus.

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

available cash: For any quarter ending prior to liquidation:

(a)

the sum of:

(1): all cash and cash equivalents of Rhino Resource Partners, L.P. and its subsidiaries on hand at the end of that quarter; and
(2): all additional cash and cash equivalents of Rhino Resource Partners, L.P. and its subsidiaries on hand on the date of determination of available cash for that quarter resulting from working capital borrowings made after the end of that quarter;

(b)

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

(1): provide for the proper conduct of the business of Rhino Resource Partners, L.P. and its subsidiaries (including reserves for future capital expenditures and for future credit needs of Rhino Resource Partners, L.P. and its subsidiaries) after that quarter;
(2): comply with applicable law or any debt instrument or other agreement or obligation to which Rhino Resource Partners, L.P. or any of its subsidiaries is a party or its assets are subject; and
(3): provide funds for minimum quarterly distribution and cumulative common unit arrearages for any one or more of the next four quarters;

provided, however, that our general partner may not establish cash reserves for distributions to the subordinated units unless our general partner has determined that the establishment of reserves will not prevent Rhino Resource Partners, L.P. from distributing the minimum quarterly distribution on all common units and any cumulative common unit arrearages thereon for the next four quarters; and

provided, further, that disbursements made by Rhino Resource Partners, L.P. or any of its subsidiaries or cash reserves established, increased or reduced after the end of that quarter but on or before the date of determination of available cash for that quarter shall be deemed to have been made, established,

B-1

increased or reduced, for purposes of determining available cash, within that quarter if the general partner so determines.

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

capital account: The capital account maintained for a partner under the partnership agreement. The capital account in respect of a general partner interest, a common unit, a subordinated unit, an incentive distribution right or any other partnership interest will be the amount which that capital account would be if that general partner interest, common unit, subordinated unit, incentive distribution right or other partnership interest were the only interest in Rhino Resource Partners, L.P. held by a partner.

capital surplus: All available cash distributed by Rhino Resource Partners, L.P. 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 as of the end of the quarter before that distribution. Any excess available cash will be deemed to be "capital surplus."

closing price: The last sale price on a day, regular way, or in case no sale takes place on that day, the average of the closing bid and asked prices on that day, regular way, as reported in the principal consolidated transaction reporting system for securities listed on the principal national securities exchange on which the units of that class are listed. If the units of that class are not listed on any national securities exchange, the last quoted price on that day. If no quoted price exists, the average of the high bid and low asked prices on that day in the over-the-counter market, as reported by the NASDAQ Global Select Market or any other system then in use. If on any day the units of that class are not quoted by any organization of that type, the average of the closing bid and asked prices on that day as furnished by a professional market maker making a market in the units of the class selected by our general partner. If on that day no market maker is making a market in the units of that class, the fair value of the units on that day as determined by our general partner.

common unit arrearage: The amount by which the minimum quarterly distribution for a quarter during the subordination period exceeds the distribution of available cash from operating surplus actually made for that quarter on a common unit, cumulative for that quarter and all prior quarters during the subordination period.

current market price: For any class of units as of any date, the average of the daily closing prices for the 20 consecutive trading days immediately prior to that date.

GAAP: Generally accepted accounting principles in the United States.

incentive distribution right: A non-voting limited partner partnership interest issued to the general partner. The partnership interest will confer upon its holder only the rights and obligations specifically provided in the partnership agreement for incentive distribution rights.

incentive distributions: The distributions of available cash from operating surplus made to holders of the incentive distribution rights.

interim capital transactions: The following transactions if they occur prior to liquidation:

(a)

borrowings, refinancings or refundings of indebtedness (other than for working capital borrowings and other than for items purchased on open account in the ordinary course of business) by Rhino Resource Partners, L.P. or any of its subsidiaries and sales of any debt securities of Rhino Resource Partners, L.P. or any of its subsidiaries;

(1): sales of equity interests by Rhino Resource Partners, L.P. or any of its subsidiaries;

B-2

(2): sales or other voluntary or involuntary dispositions of any assets of Rhino Resource Partners, L.P. or any of its subsidiaries (other than sales or other dispositions of inventory, accounts receivable and other assets in the ordinary course of business, and sales or other dispositions of assets as a part of normal retirements or replacements);
(3): the termination of interest rate swap agreements;
(4): capital contributions; and
(5): corporate reorganizations or restructurings.

limestone: A rock predominantly composed of the mineral calcite (calcium carbonate (CaCO₂)).

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

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

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

operating expenditures: All expenditures of Rhino Resource Partners, L.P. and its subsidiaries (or Rhino Resource Partners, L.P.'s proportionate share in the case of subsidiaries that are not wholly owned), including, but not limited to, taxes, reimbursements of the general partner, non-pro rata repurchases of units (other than those made with proceeds of an interim capital transaction), repayment of working capital borrowings, debt service payments and estimated maintenance and replacement capital expenditures, provided that operating expenditures will not include:

(1): payments (including prepayments) of principal of and premium on indebtedness, other than working capital borrowings will not constitute operating expenditures;
(2): capital expenditures made for acquisitions or for capital improvements, or expansion capital expenditures;
(3): actual maintenance and replacement capital expenditures;
(4): investment capital expenditures;
(5): payment of transaction expenses relating to interim capital transactions; or
(6): distributions to partners.

B-3

Where capital expenditures are made in part for acquisitions or for capital improvements and in part for other purposes, the general partner, with the concurrence of the conflicts committee, shall determine the allocation between the amounts paid for each.

operating surplus: For any period prior to liquidation, on a cumulative basis and without duplication:

(a)

the sum of

(1): $30.0 million;
(2): all cash receipts of Rhino Resource Partners, L.P. and its subsidiaries (or Rhino Resource Partners, L.P.'s proportionate share in the case of subsidiaries that are not wholly owned) for the period beginning on the closing date of the initial public offering and ending with the last day of that period, other than cash receipts from interim capital transactions;
(3): all cash receipts of Rhino Resource Partners, L.P. and its subsidiaries (or Rhino Resource Partners, L.P.'s proportionate share in the case of subsidiaries that are not wholly owned) after the end of that period but on or before the date of determination of operating surplus for the period resulting from working capital borrowings; and
(4): the amount of distributions paid on equity issued in connection with the construction of a capital improvement or replacement asset and paid during the period on the date that Rhino Resource Partners, L.P. enters into a binding obligation to commence construction of such capital improvement or replacement asset and ending on the date that such capital improvement or replacement asset either commences service or is abandoned or disposed of; less

(b)

the sum of:

(1): operating expenditures for the period beginning on the closing date of the initial public offering and ending with the last day of that period and the repayment of working capital borrowings, but not (A) the repayment of other borrowings, (B) actual maintenance and replacement capital expenditures or expansion capital expenditures, (C) transaction expenses (including taxes) related to interim capital transactions or (D) distributions; and
(2): estimated maintenance and replacement capital expenditures and the amount of cash reserves established by the general partner (or Rhino Resource Partners, L.P.'s proportionate share in the case of subsidiaries that are not wholly owned) to provide funds for future operating expenditures; provided however, that disbursements made (including contributions to a member of Rhino Resource Partners, L.P. and its subsidiaries or disbursements on behalf of a member of Rhino Resource Partners, L.P. and its subsidiaries) or cash reserves established, increased or reduced after the end of that period but on or before the date of determination of available cash for that period shall be deemed to have been made, established, increased or reduced for purposes of determining operating surplus, within that period if the general partner so determines.

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

proven (measured) reserves: Reserves for which (a) quantity is computed from dimensions revealed in outcrops, trenches, workings or drill holes; grade and/or quality are computed from the results of detailed sampling and (b) the sites for inspection, sampling and measurement are spaced so closely and

B-4

the geologic character is so well defined that size, shape, depth and mineral content of reserves are well-established.

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

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

subordination period: The subordination period will generally extend from the closing of the initial public offering until the first to occur of:

(a)

the first day of any quarter beginning after June 30, 2013 for which:

(1): distributions of available cash from operating surplus on each of the outstanding common units and subordinated units equaled or exceeded the sum of the minimum quarterly distribution on all of the outstanding common units and subordinated units for each of the three consecutive, non-overlapping four-quarter periods immediately preceding that date;
(2): the adjusted operating surplus 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 common units and subordinated units that were outstanding during those periods on a fully diluted basis, and the general partner interest; and
(3): there are no outstanding cumulative common units arrearages; and

(b)

the date on which the general partner is removed as general partner of Rhino Resource Partners, L.P. upon the requisite vote by the limited partners under circumstances where cause does not exist and units held by our general partner and its affiliates are not voted in favor of the removal.

units: Refers to both common units and subordinated units.

working capital borrowings: Borrowings used exclusively for working capital purposes or to pay distributions to partners, made pursuant to a credit agreement or other arrangement to the extent such borrowings are required to be reduced to a relatively small amount each year for an economically meaningful period of time.

B-5

5,000,000 Common Units
Representing Limited Partner Interests

PROSPECTUS
, 2008

LEHMAN BROTHERS

PART II
INFORMATION NOT REQUIRED IN THE PROSPECTUS

Item 13. Other Expenses of Issuance and Distribution.

Set forth below are the expenses (other than the underwriting discount) expected to be incurred in connection with the issuance and distribution of the securities registered hereby. With the exception of the Securities and Exchange Commission registration fee, the FINRA filing fee and the NASDAQ Global Select Market listing fee, the amounts set forth below are estimates.

SEC registration fee		$	4,520
FINRA filing fee			12,000
NASDAQ Global Select Market listing fee			100,000
Printing and engraving expenses			*
Fees and expenses of legal counsel			*
Accounting fees and expenses			*
Transfer agent fees			3,500
Miscellaneous			*

	Total	$	*

*: To be provided by amendment.

Item 14. Indemnification of Directors and Officers.

The section of the prospectus entitled "The Partnership Agreement—Indemnification" discloses that we will generally indemnify officers, directors and affiliates of our general partner to the fullest extent permitted by the law against all losses, claims, damages or similar events and is incorporated herein by this reference. Reference is also made to the Underwriting Agreement to be filed as an amendment / Exhibit 1.1 to this registration statement in which Rhino GP LLC and certain of its affiliates will agree to indemnify and hold harmless the underwriters against certain liabilities including liabilities under the Securities Act of 1933, as amended, and to contribute to payments that may be required to be made in respect of these liabilities. Subject to any terms, conditions or restrictions set forth in the partnership agreement, Section 17-108 of the Delaware Revised Uniform Limited Partnership Act empowers a Delaware limited partnership to indemnify and hold harmless any partner or other person from and against all claims and demands whatsoever. As of the consummation of this offering, the general partner of the registrant will maintain directors and officers liability insurance for the benefit of its directors and officers.

Item 15. Recent Sales of Unregistered Securities.

On January 11, 2006, in connection with the formation of the partnership, Rhino Resource Partners, L.P. issued (1) to Rhino GP LLC the 2% general partner interest in the partnership for $20 and (2) to Rhino Energy Holdings LLC the 98% limited partner interest in the partnership for $980 in an offering exempt from registration under Section 4(2) of the Securities Act of 1933. There have been no other sales of unregistered securities within the past three years.

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Item 16. Exhibits and Financial Statement Schedules.

(a): The following documents are filed as exhibits to this registration statement:

Exhibit Number	Description
1.1**	—	Form of Underwriting Agreement
3.1*	—	Certificate of Limited Partnership of Rhino Resource Partners, L.P., as amended
3.2**	—	Form of First Amended and Restated Agreement of Limited Partnership of Rhino Resource Partners, L.P. (included as Appendix A to the Prospectus)
5.1**	—	Opinion of Vinson & Elkins L.L.P. as to the legality of the securities being registered
8.1**	—	Opinion of Vinson & Elkins L.L.P. relating to tax matters
10.1**	—	Credit Agreement by and among CAM Holdings LLC, the Guarantors Party Thereto, the Lenders Party Thereto, PNC Bank, National Association, as Administrative Agent, PNC National Markets LLC and National City Bank as Joint Lead Arrangers, and Wachovia Bank, National Association, Royal Bank of Canada and Raymond James Bank, FSB, as Co-Documentations Agents dated as of August 30, 2006
10.2**	—	First Amendment to the Credit Agreement dated December 28, 2006 by and among CAM Holdings LLC, each of the Guarantors (as defined therein), the Lenders Party Thereto, and PNC Bank, National Association, in as administrative agent for the Lenders
10.3**	—	Second Amendment to the Credit Agreement and Consent dated March 8, 2007 by and among Rhino Energy LLC, a Delaware limited liability company formerly known as CAM Holdings LLC, each of the Guarantors (as defined therein), the Lenders Party Thereto, and PNC Bank, National Association, in as administrative agent for the Lenders
10.4**	—	Third Amendment to the Credit Agreement dated February 29, 2008 by and among Rhino Energy LLC, a Delaware limited liability company formerly known as CAM Holdings LLC, each of the Guarantors (as defined therein), the Lenders Party Thereto, and PNC Bank, National Association, in as administrative agent for the Lenders
10.5**	—	Form of Fourth Amendment to the Credit Agreement
10.6**	—	Form of Contribution, Conveyance and Assumption Agreement
10.7**	—	Form of Rhino Resource Partners, L.P. Long-Term Incentive Plan
10.8**	—	Colorado Mining Agreement between CAM-Colorado LLC and CAM Mining LLC
10.9**	—	Form of Shared Services Agreement
10.10**	—	Employment Agreement between Rhino GP LLC and Nicholas R. Glancy
10.11**	—	Employment Agreement between Rhino GP LLC and Richard A. Boone
10.12**	—	Employment Agreement between Rhino GP LLC and David G. Zatezalo
10.13**	—	Employment Agreement between Rhino GP LLC and Christopher N. Moravec
10.14**	—	Employment Agreement between Rhino GP LLC and Thomas Hanley
10.15**	—	Form of Long-Term Incentive Plan Grant Agreement
10.16**	—	Director Compensation Information
21.1*	—	List of Subsidiaries of Rhino Resource Partners, L.P.
23.1*	—	Consents of Deloitte & Touche LLP

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23.2*	—	Consent of Marshall Miller & Associates, Inc.
23.3**	—	Consent of Vinson & Elkins L.L.P. (contained in Exhibit 5.1)
23.4**	—	Consent of Vinson & Elkins L.L.P. (contained in Exhibit 8.1)
24.1*	—	Powers of Attorney (included on the signature page)
99.1*	—	Consent of Director Nominee

*

Filed herewith.

To be filed by amendment.

(b): Financial Statements Schedules.

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REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

To the Members of
Rhino Energy LLC
Lexington, Kentucky

We have audited the consolidated financial statements of Rhino Energy LLC (the "Company") as of December 31, 2007 and 2006, and for the year ended March 31, 2006, the nine months ended December 31, 2006 and the year ended December 31, 2007, and have issued our report thereon dated April 10, 2008 (which report expresses an unqualified opinion and includes explanatory paragraphs concerning the adoption of SFAS No. 158, Employer's Accounting for Defined Benefit Pension and other Postretirement Plans—an amendment of FASB Statements No. 87, 88, 106 and 132(R), and a change in the Company's fiscal year end), included elsewhere in this Registration Statement. Our audits also included the consolidated financial statement schedule appearing in Item 16(b) of this Registration Statement. This consolidated financial statement schedule is the responsibility of the Company's management. Our responsibility is to express an opinion based on our audits. In our opinion, such consolidated financial statement schedule, when considered in relation to the basic consolidated financial statements taken as a whole, presents fairly in all material respects the information set forth therein.

/s/ Deloitte & Touche LLP

Cincinnati, Ohio

April 10, 2008

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	Balance at Beginning of Period		Additions		Deductions		Balance at End of Period
For the year ended December 31, 2007
Allowance for doubtful accounts	$	175,242	$	—	$	175,242	$	—
For the nine months ended December 31, 2006
Allowance for doubtful accounts	$	458,000	$	175,242	$	458,031	$	175,242
For the year ended March 31, 2006
Allowance for doubtful accounts	$	104,000	$	458,000	$	104,000	$	458,000

Item 17. Undertakings.

The undersigned registrant hereby undertakes to provide to the underwriters at the closing specified in the underwriting agreement, certificates in such denominations and registered in such names as required by the underwriters to permit prompt delivery to each purchaser.

Insofar as indemnification for liabilities arising under the Securities Act of 1933 may be permitted to directors, officers and controlling persons of the registrant pursuant to the foregoing provisions, or otherwise, the registrant has been advised that in the opinion of the Securities and Exchange Commission such indemnification is against public policy as expressed in the Securities Act of 1933 and is, therefore, unenforceable. In the event that a claim for indemnification against such liabilities (other than the payment by the registrant of expenses incurred or paid by a director, officer or controlling person of the registrant in the successful defense of any action, suit or proceeding) is asserted by such director, officer or controlling person in connection with the securities being registered, the registrant will, unless in the opinion of its counsel the matter has been settled by controlling precedent, submit to a court of appropriate jurisdiction of the question whether such indemnification by it is against public policy as expressed in the Securities Act of 1933 and will be governed by the final adjudication of such issue.

The undersigned registrant hereby undertakes that:

(1): For purposes of determining any liability under the Securities Act of 1933, the information omitted from the form of prospectus filed as part of this registration statement in reliance upon Rule 430A and contained in a form of prospectus filed by the registrant pursuant to Rule 424(b)(1) or (4) or 497(h) under the Securities Act of 1933 shall be deemed to be part of this registration statement as of the time it was declared effective.
(2): For the purpose of determining any liability under the Securities Act of 1933, each post-effective amendment that contains a form of prospectus shall be deemed to be a new registration statement relating to the securities offered therein, and the offering of such securities at that time shall be deemed to be the initial bona fide offering thereof.

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SIGNATURES

Pursuant to the requirements of the Securities Act of 1933, the registrant has duly caused this Registration Statement to be signed on its behalf by the undersigned, thereunto duly authorized, in the City of Lexington, State of Kentucky, on April 15, 2008.

RHINO RESOURCE PARTNERS, L.P.
By:	Rhino GP LLC its General Partner
	By:	/s/ NICHOLAS R. GLANCY Nicholas R. Glancy Chief Executive Officer

Each person whose signature appears below appoints Nicholas R. Glancy and Richard A. Boone, and each of them, any of whom may act without the joinder of the other, as his true and lawful attorneys-in-fact and agents, with full power of substitution and resubstitution, for him and in his name, place and stead, in any and all capacities, to sign any and all amendments (including post-effective amendments) to this Registration Statement and any Registration Statement (including any amendment thereto) for this offering that is to be effective upon filing pursuant to Rule 462(b) under the Securities Act of 1933 and to file the same, with all exhibits thereto, and all other documents in connection therewith, with the Securities and Exchange Commission, granting unto said attorneys-in-fact and agents full power and authority to do and perform each and every act and thing requisite and necessary to be done, as fully to all intents and purposes as he might or would do in person, hereby ratifying and confirming all that said attorneys-in-fact and agents or any of them of their or his substitute and substitutes, may lawfully do or cause to be done by virtue hereof.

Pursuant to the requirements of the Securities Act of 1933, this Registration Statement has been signed below by the following persons in the capacities indicated on April 15, 2008.

Signature		Title
/s/ NICHOLAS R. GLANCY Nicholas R. Glancy		President and Chief Executive Officer and Director (Principal Executive Officer)
/s/ RICHARD A. BOONE Richard A. Boone		Senior Vice President and Chief Financial Officer (Principal Financial Officer and Principal Accounting Officer)
/s/ MARK D. ZAND Mark D. Zand		Chairman of the Board
/s/ JAY L. MAYMUDES Jay L. Maymudes		Vice President—Finance and Administration, Secretary and Director
/s/ ARTHUR H. AMRON Arthur H. Amron		Vice President, Assistant Secretary and Director
/s/ KENNETH A. RUBIN Kenneth A. Rubin		Director

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EXHIBIT INDEX

Exhibit Number	Description
1.1**	—	Form of Underwriting Agreement
3.1*	—	Certificate of Limited Partnership of Rhino Resource Partners, L.P., as amended
3.2**	—	Form of First Amended and Restated Agreement of Limited Partnership of Rhino Resource Partners, L.P. (included as Appendix A to the Prospectus)
5.1**	—	Opinion of Vinson & Elkins L.L.P. as to the legality of the securities being registered
8.1**	—	Opinion of Vinson & Elkins L.L.P. relating to tax matters
10.1**	—	Credit Agreement by and among CAM Holdings LLC, the Guarantors Party Thereto, the Lenders Party Thereto, PNC Bank, National Association, as Administrative Agent, PNC National Markets LLC and National City Bank as Joint Lead Arrangers, and Wachovia Bank, National Association, Royal Bank of Canada and Raymond James Bank, FSB, as Co-Documentations Agents dated as of August 30, 2006
10.2**	—	First Amendment to the Credit Agreement dated December 28, 2006 by and among CAM Holdings LLC, each of the Guarantors (as defined therein), the Lenders Party Thereto, and PNC Bank, National Association, in as administrative agent for the Lenders
10.3**	—	Second Amendment to the Credit Agreement and Consent dated March 8, 2007 by and among Rhino Energy LLC, a Delaware limited liability company formerly known as CAM Holdings LLC, each of the Guarantors (as defined therein), the Lenders Party Thereto, and PNC Bank, National Association, in as administrative agent for the Lenders
10.4**	—	Third Amendment to the Credit Agreement dated February 29, 2008 by and among Rhino Energy LLC, a Delaware limited liability company formerly known as CAM Holdings LLC, each of the Guarantors (as defined therein), the Lenders Party Thereto, and PNC Bank, National Association, in as administrative agent for the Lenders
10.5**	—	Form of Fourth Amendment to the Credit Agreement
10.6**	—	Form of Contribution, Conveyance and Assumption Agreement
10.7**	—	Form of Rhino Resource Partners, L.P. Long-Term Incentive Plan
10.8**	—	Colorado Mining Agreement between CAM-Colorado LLC and CAM Mining LLC
10.9**	—	Form of Shared Services Agreement
10.10**	—	Employment Agreement between Rhino GP LLC and Nicholas R. Glancy
10.11**	—	Employment Agreement between Rhino GP LLC and Richard A. Boone
10.12**	—	Employment Agreement between Rhino GP LLC and David G. Zatezalo
10.13**	—	Employment Agreement between Rhino GP LLC and Christopher N. Moravec
10.14**	—	Employment Agreement between Rhino GP LLC and Thomas Hanley
10.15**	—	Form of Long-Term Incentive Plan Grant Agreement
10.16**	—	Director Compensation Information
21.1*	—	List of Subsidiaries of Rhino Resource Partners, L.P.
23.1*	—	Consents of Deloitte & Touche LLP

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23.2*	—	Consent of Marshall Miller & Associates, Inc.
23.3**	—	Consent of Vinson & Elkins L.L.P. (contained in Exhibit 5.1)
23.4**	—	Consent of Vinson & Elkins L.L.P. (contained in Exhibit 8.1)
24.1*	—	Powers of Attorney (included on the signature page)
99.1*	—	Consent of Director Nominee

*: Filed herewith.
**: To be filed by amendment.

II-8