UNITED STATES
SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

Form 10-K

þ		ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

o		TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

COMMISSION FILE NO.: 001-34815

OXFORD RESOURCE PARTNERS, LP

(Exact name of registrant as specified in its charter)

Delaware		77-0695453
(STATE OR OTHER JURISDICTION OF		(IRS EMPLOYER
INCORPORATION OR ORGANIZATION)		IDENTIFICATION NO.)

41 South High Street, Suite 3450, Columbus, Ohio 43215
(Address Of Principal Executive Offices And Zip Code)

(614) 643-0314
(Registrant’s telephone number, including area code)

Title of Each Class		Name of Each Exchange On Which Registered
Common Units Representing Limited Partner Interests		New York Stock Exchange

Securities registered pursuant to Section 12(g) of the Act: None

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

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

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

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

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

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 þ		Smaller Reporting Company o

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

As of June 30, 2010, the last business day of the registrant’s second fiscal quarter of 2010, the registrant’s common units were not listed on any exchange or over-the-counter market. The registrant’s common units began trading on the New York Stock Exchange on July 14, 2010. The aggregate market value of the common units held by non-affiliates of the registrant (treating all executive officers and directors of the registrant, for this purpose, as if they may be affiliates of the registrant) was approximately $251,653,000 as of December 31, 2010, based on the reported closing price of the common units as reported on the New York Stock Exchange on such date.

As of March 14, 2011, 10,341,416 common units and 10,280,380 subordinated units were outstanding. The common units trade on the New York Stock Exchange under the ticker symbol “OXF.”

DOCUMENTS INCORPORATED BY REFERENCE: None

 

 

TABLE OF CONTENTS

		Page
Cautionary Statement About Forward-Looking Statements		ii
Glossary of Selected Mining Terms		iv
PART I
Item 1. Business			1
Item 1A. Risk Factors			25
Item 1B. Unresolved Staff Comments			42
Item 2. Properties			43
Item 3. Legal Proceedings			45
Item 4. Reserved			45
PART II
Item 5. Market for Registrant’s Common Equity, Related Unitholder Matters and Issuer Purchases of Equity Securities			46
Item 6. Selected Financial and Operating Data			48
Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations			52
Item 7A. Quantitative and Qualitative Disclosures About Market Risk			71
Item 8. Financial Statements and Supplementary Data			72
Item 9. Changes in and Disagreements With Accountant on Accounting and Financial Disclosure			72
Item 9A. Controls and Procedures			72
Item 9B. Other Information			73
PART III
Item 10. Directors, Executive Officers and Corporate Governance			74
Item 11. Executive Compensation			79
Item 12. Security Ownership of Certain Beneficial Owners and Management and Related Unitholder Matters			93
Item 13. Certain Relationships and Related Transactions, and Director Independence			97
Item 14. Principal Accountant Fees and Services			100
PART IV
Item 15. Exhibits and Financial Statement Schedules			101
Exhibit 10.22
Exhibit 21.1
Exhibit 23.1
Exhibit 23.2
Exhibit 31.1
Exhibit 31.2
Exhibit 32.1
Exhibit 32.2

CAUTIONARY STATEMENT ABOUT FORWARD-LOOKING STATEMENTS

This Annual Report on Form 10-K contains certain “forward-looking statements.” Statements included in this Annual Report on Form 10-K that are not historical facts, that address activities, events or developments that we expect or anticipate will or may occur in the future, including things such as plans for growth of the business, future capital expenditures, competitive strengths, goals, references to future goals or intentions or other such references, are forward-looking statements. These statements can be identified by the use of forward-looking terminology, including “may,” “believe,” “expect,” “anticipate,” “estimate,” “continue” or similar words. These statements are made by us based on our past experience and our perception of historical trends, current conditions and expected future developments as well as other considerations we believe are appropriate under the circumstances. Whether actual results and developments in the future will conform to our expectations is subject to numerous risks and uncertainties, many of which are beyond our control. Therefore, actual outcomes and results could materially differ from what is expressed, implied or forecasted in these statements. Any differences could be caused by a number of factors, including but not limited to:

•

our production levels, margins earned and level of operating costs;

•

weakness in global economic conditions or in our customers’ industries;

•

changes in governmental regulation of the mining industry or the electric power industry and the increased costs of complying with those changes;

•

decreases in demand for electricity and changes in coal consumption patterns of U.S. electric power generators;

•

our dependence on a limited number of customers;

•

our inability to enter into new long-term coal sales contracts at attractive prices and the renewal and other risks associated with our existing long-term coal sales contracts, including risks related to adjustments to price, volume or other terms of those contracts;

•

difficulties in collecting our receivables because of credit or financial problems of major customers, and customer bankruptcies, cancellations or breaches of existing contracts, or other failures to perform;

•

our ability to acquire additional coal reserves;

•

our ability to respond to increased competition within the coal industry;

•

fluctuations in coal demand, prices and availability due to labor and transportation costs and disruptions, equipment availability, governmental regulations, including those pertaining to carbon dioxide emissions, and other factors;

•

significant costs imposed on our mining operations by extensive and frequently changing environmental laws and regulations, and greater than expected environmental regulation, costs and liabilities;

•

legislation, and regulatory and related judicial decisions and interpretations, including issues pertaining to climate change and miner health and safety;

•

a variety of operational, geologic, permitting, labor and weather-related factors, including those pertaining to both our mining operations and our underground coal reserves that we do not operate;

•

limitations in the cash distributions we receive from our majority-owned subsidiary, Harrison Resources, LLC, and the ability of Harrison Resources to acquire additional reserves on economical terms from CONSOL Energy Inc. in the future;

•

the potential for inaccuracies in our estimates of our coal reserves, which could result in lower than expected revenues or higher than expected costs;

•

the accuracy of the assumptions underlying our reclamation and mine closure obligations;

•

liquidity constraints, including those resulting from the cost or unavailability of financing due to current capital markets conditions;

•

risks associated with major mine-related accidents;

•

results of litigation, including claims not yet asserted;

•

our ability to attract and retain key management personnel;

•

greater than expected shortage of skilled labor;

•

our ability to maintain satisfactory relations with our employees; and

•

failure to obtain, maintain or renew our security arrangements, such as surety bonds or letters of credit, in a timely manner and on acceptable terms.

When considering forward-looking statements, you should keep in mind the risk factors and other cautionary statements set forth in this Annual Report on Form 10-K as well as other written and oral statements made or incorporated by reference from time to time by us in other reports and filings with the Securities and Exchange Commission, or the SEC. All forward-looking statements included in this Annual Report on Form 10-K and all subsequent written or oral forward-looking statements attributable to us or persons acting on our behalf are expressly qualified in their entirety by these cautionary statements. The forward-looking statements speak only as of the date made, other than as required by law, and we undertake no obligation to publicly update or revise any forward-looking statements, whether as a result of new information, future events or otherwise.

Glossary of Selected Mining Terms

base-load power plants: The electrical generation facilities used to meet some or all of a given region’s continuous energy demand and produce energy at a constant rate.

base-load scrubbed power plants: Base-load power plants that are scrubbed power plants.

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

dozer: A large, powerful tractor having a vertical blade at the front end for moving earth, rocks, etc.

highwall: The unexcavated face of exposed overburden and coal in a surface mine or in a face or bank on the uphill side of a contour mine excavation.

industrial boilers: Closed vessels that use a fuel source to heat water or generate steam for industrial heating and humidification applications.

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.

probable coal reserves: Coal reserves for which quantity and grade and/or quality are computed from information similar to that used for proven coal 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 coal reserves, is high enough to assume continuity between points of observation.

proven coal reserves: Coal reserves for which (i) quantity is computed from dimensions revealed in outcrops, trenches, workings or drill holes; (ii) grade and/or quality are computed from the results of detailed sampling; and (iii) 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 coal reserves are well-established.

proven and probable coal reserves: Coal reserves which are a combination of proven coal reserves and probable coal reserves.

reclamation: The restoration of mined land to original contour, use or condition.

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

scrubbed power plant: A power plant that uses scrubbers to clean the gases that pass through its smokestacks.

scrubbers: Air pollution control devices that can be used to remove some particulates and chemical compounds from industrial exhaust streams.

selective catalytic reduction, or SCR, device: A means of converting nitrogen oxides, also referred to as NOx, with the aid of a catalyst into diatomic nitrogen (N2) and water (H2O).

spoil-piles: Earth and rock removed from a coal deposit and temporarily stored during excavation.

steam coal: Coal used by power plants and industrial steam boilers to produce electricity, steam or both.

strip ratio: In open pit mining, strip ratio refers to the number of tons of overburden or waste that must be removed to extract one ton of coal.

tipple: A structure where coal is cleaned and loaded in railroad cars or trucks.

total maximum daily load: A calculation of the maximum amount of a pollutant that a body of water can receive per day and still safely meet water quality standards.

PART I

ITEM 1.		BUSINESS

Overview

We are a low cost producer of high value steam coal, and we are the largest producer of surface mined coal in Ohio. We focus on acquiring steam coal reserves that we can efficiently mine with our modern, large scale equipment. Our reserves and operations are strategically located in Northern Appalachia and the Illinois Basin to serve our primary market area of Illinois, Indiana, Kentucky, Ohio, Pennsylvania and West Virginia. We market our coal primarily to large utilities with coal-fired, base-load scrubbed power plants under long-term coal sales contracts.

We currently have 21 active surface mines, two of which became active mines in 2011, that are managed as eight mining complexes. Our operations also include two river terminals, strategically located in eastern Ohio and western Kentucky. During 2010, we produced 7.5 million tons of coal. During 2010, we sold 8.1 million tons of coal, including 0.7 million tons of purchased coal. As a result, our coal inventory on hand increased by approximately 0.1 million tons. As is customary in the coal industry, we have entered into long-term coal sales contracts with many of our customers. We define long-term coal sales contracts as coal sales contracts having initial terms of one year or more.

As of December 31, 2010, we owned and/or controlled 93.5 million tons of proven and probable coal reserves, of which 68.1 million tons were associated with our surface mining operations and the remaining 25.4 million tons consisted of underground coal reserves that we have subleased to a third party in exchange for an overriding royalty. Historically, we have been successful at replacing the reserves depleted by our annual production and growing our reserve base by acquiring reserves with low operational, geologic and regulatory risks and that were located near our mining operations or that otherwise had the potential to serve our primary market area. In 2010, we acquired 8.7 million tons of proven and probable coal reserves, an amount equal to 109% of our 2010 production.

The following table summarizes our mining complexes, our coal production for the year ended December 31, 2010 and our coal reserves as of December 31, 2010:

						As of December 31, 2010
		Production for				Total												Average				Average
		the Year Ended				Proven &												Heat				Sulfur				Primary
		December 31,				Probable				Proven				Probable				Value				Content				Transportation
Mining Complexes		2010				Reserves(1)				Reserves(1)				Reserves(1)				(BTU/lb.)				(%)				Methods
		(in million tons)
Surface Mining Operations:
Northern Appalachia - (principally Ohio)
Cadiz (2)			1.4				10.9				10.9				—				11,500				3.4			Barge, Rail
Tuscarawas County (2)			0.9				7.6				7.6				—				11,670				3.9			Truck
Plainfield			0.3				6.4				6.4				—				11,460				4.4			Truck
Belmont County			1.1				6.2				5.9				0.3				11,620				3.8			Barge
New Lexington			0.6				5.7				5.4				0.3				11,550				3.9			Rail
Harrison(3)			1.0				5.1				4.9				0.2				12,000				1.8			Barge, Rail, Truck
Noble County			0.5				2.7				2.7				—				11,200				4.7			Barge, Truck
Illinois Basin (Kentucky)															—
Muhlenberg County			1.7				23.5				22.8				0.7				11,309				3.6			Barge, Truck
Total Surface Mining Operations			7.5				68.1				66.6				1.5
Underground Coal Reserves:
Northern Appalachia (Ohio)
Tusky(4)							25.4				20.0				5.4				12,910				2.1
Total Underground Coal Reserves							25.4				20.0				5.4
Total							93.5				86.6				6.9

We are a Delaware limited partnership that is listed on the New York Stock Exchange, or NYSE, under the ticker symbol “OXF.” On July 19, 2010, we closed our initial public offering of common units. After deducting underwriting discounts and commissions of approximately $10.5 million paid to the underwriters, our offering expenses of approximately $6.1 million and a structuring fee of approximately $0.8 million, the net proceeds from our initial public offering were approximately $144.5 million.

We were formed in August 2007 by American Infrastructure MLP Fund, L.P., or AIM, and C&T Coal, Inc., or C&T Coal. AIM is a private investment firm specializing in natural resources, infrastructure and real property. AIM, along with certain of the funds that AIM advises, indirectly owns all of the ownership interests in AIM Oxford Holdings, LLC, or AIM Oxford, the entity it used to form us in 2007. Brian D. Barlow, Matthew P. Carbone and George E. McCown serve on the board of directors of our general partner and are principals of AIM and have ownership interests in AIM. C&T Coal is owned by our founders, Charles C. Ungurean, the President and Chief Executive Officer of our general partner and a member of the board of directors of our general partner, and Thomas T. Ungurean, the Senior Vice President, Equipment, Procurement and Maintenance of our general partner. Each of our two founders has over 38 years of experience in the coal mining industry. In connection with our formation, our founders contributed all of their interests in Oxford Mining Company to us and agreed that they would not compete with us in the coal mining business in Illinois, Kentucky, Ohio, Pennsylvania, West Virginia and Virginia. This non-compete agreement is in effect until August 24, 2014.

Our founders formed Oxford Mining Company in 1985 to provide contract mining services to a mining division of a major oil company. In 1989, our founders transitioned Oxford Mining Company from a contract miner into a producer of its own coal reserves. In January 2007, Oxford Mining Company entered into a joint venture, Harrison Resources, with a subsidiary of CONSOL Energy to mine surface coal reserves purchased from CONSOL Energy. In September 2009, we completed the acquisition of Phoenix Coal’s active surface mining operations. The Phoenix Coal acquisition provided us with an entry into the Illinois Basin in western Kentucky and included one mining complex comprised of four mines as well as the Island river terminal on the Green River in western Kentucky.

Industry Overview

Coal is ranked by heat content, with bituminous, sub-bituminous and lignite coal representing the highest to lowest heat ranking, respectively. Coal is also categorized as either steam coal or metallurgical coal. Steam coal is used by utilities and independent power producers to generate electricity and metallurgical coal is used by steel companies to produce metallurgical coke for use in blast furnaces. The U.S. Department of Energy’s Energy Information Administration, or the EIA, forecasts that coal-fired electric power generation will increase by 13.0% through 2015 and by 27.0% through 2035, with steam coal remaining the dominant fuel source in the future.

Coal Quality Characteristics

Coal quality is primarily differentiated by its heat and sulfur content. Heat content is measured in Btu per pound (Btu/lb). In general, coal with low moisture and ash content has high heat content. Coal with higher heat content commands higher prices because less coal is needed to generate a given quantity of electric power.

Sulfur content is measured in pounds of sulfur dioxide emitted per million Btu of fuel combusted. When coal is burned, sulfur dioxide and other air emissions are released. Compliance coal is a term generally used in the United States to describe coal or a blend of coals that, when burned, emits less than 1.2 lbs of sulfur dioxide per million Btu and complies with the requirements of the Clean Air Act Amendments of 1990, or the CAAA, without the use of scrubbers. The primary reserves of compliance coal are found in both the Powder River Basin, or PRB, and Central Appalachia.

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 more than 90%. Plants without scrubbers can burn high sulfur coal by blending it with lower sulfur coal, or by purchasing emission allowances on the open market.

Coal ash and chlorine content also can influence the marketability of a particular coal. Ash is the inorganic residue remaining after the combustion of coal. Ash content is also an important characteristic of coal because electric generating plants must handle and dispose of ash following combustion. The chlorine content of coal is important to generating station operators since high levels can adversely impact boiler performance directly by both high and low temperature corrosion and indirectly by reacting with other coal impurities to cause ash fouling. As with sulfur, coal of various ash contents can be blended to meet the specific combustion and environmental needs of customers.

Coal Mining Methods

Coal is mined using two primary methods, surface mining and underground 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 generally involves removing the 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. Surface mining methods generally encompass highwall and auger mining methods. After a final highwall is established by other surface mining methods, a highwall miner or auger is used to recover additional reserves from the coal seam in place without additional overburden removal. A highwall miner is similar to a continuous miner used in underground mining connected to a conveyor system to remove coal as the highwall miner advances into the coal seam underground from the open highwall face. Underground mining is generally used when the coal seam is too deep to permit surface mining.

Transportation

The U.S. coal industry is dependent on the availability of a consistent and responsive transportation network connecting the various supply regions to the domestic and international markets. Railroads and barges comprise the foundation of the domestic coal distribution system, collectively handling about three-quarters of all coal shipments. Truck and conveyor systems typically move coal over shorter distances.

Although the purchaser typically bears the freight costs, transportation costs are still important to coal mining companies because the purchaser may choose a supplier largely based on the total delivered cost of coal, which includes the cost of transportation. Coal used for domestic consumption may be sold free-on-board at the mine, or FOB mine, which means the purchaser normally bears the transportation costs. Transportation can be a large component of a purchaser’s total cost.

While coal can sometimes be moved by one transportation method to market, it is common for two or more modes to be used to ship coal (i.e., inter-modal movements). The method of transportation and the delivery distance greatly impact the total cost of coal delivered to the customer.

Overview of U.S. Market

The majority of coal consumed in the United States is used to generate electricity, with the balance used by a variety of industrial users to heat and power foundries, cement plants, paper mills, chemical plants and other manufacturing and processing facilities. In 2009, coal-fired power plants produced approximately 45.0% of all electric power generation and steam coal accounted for 92.0% of total coal consumption.

Short-Term Outlook

The EIA forecasts that domestic coal consumption will increase by 14.4% through 2015 and coal-fired electric power generation will increase by 13.0% through 2015. According to the EIA, coal production in Northern Appalachia and the Illinois Basin is expected to grow by 29.2% and 33.1%, respectively, through 2015. We believe that this projected increase will be driven by a combination of the continued decline in coal production in Central Appalachia and the new scrubber installations at coal-fired power plants in our primary market area of Illinois, Indiana, Kentucky, Ohio, Pennsylvania and West Virginia. Additional increases in demand are also projected in connection with new coal-to-liquids plants and carbon capture and sequestration, or CCS, technology.

U.S. exports will also continue to increase, supported by recovering global economies and continued rapid growth in electric power generation and steel production.

Increasingly stringent air quality legislation will continue to impact the demand for coal. A series of more stringent requirements have been proposed or enacted by federal or state regulatory authorities in recent years. Considerable uncertainty is associated with these air quality regulations, some of which have been the subject of legal challenges in courts, and the actual timing of implementation remains uncertain.

Mining Operations

We currently have 21 active surface mines, two of which became active mines in 2011, that are managed as eight mining complexes. We define a mining complex as a group of mines that are located in close proximity to each other or that routinely sell coal to the same customer. Our transportation facilities include two river terminals and two rail loading facilities. Our mining facilities include two wash plants, six blending facilities and eleven crushing facilities.

Our surface mining operations use area, contour, auger and highwall mining methods. Our area mining operations use truck/shovel and truck/loader equipment fleets along with large dozers. Our contour mining operations use truck/loader equipment fleets and large dozers. For our auger mining operations, we own and operate seven augers and move them among our mining complexes as necessary. For our highwall mining operations, we own and operate two Superior highwall miners and also move them among our mining complexes as necessary.

In Northern Appalachia we operate large electric and hydraulic shovels matched with a fleet of 240-ton haul trucks and 200-ton haul trucks. We also deploy a fleet of over 75 large Caterpillar D-11 and similar class dozers. We employ preventive maintenance and rebuild programs to ensure that our equipment is well-maintained. The rebuild programs are performed by third-party contractors. We assess the equipment utilized in our mining operations on an ongoing basis and replace it with new, more efficient units on an as-needed basis.

Our transportation facilities include our Bellaire river terminal located on the Ohio River in eastern Ohio, our Cadiz rail loadout facility located on the Ohio Central Railroad near Cadiz, Ohio, our New Lexington rail facility located on the Ohio Central Railroad in Perry County, Ohio and our Island river terminal and transloading facility located on the Green River in western Kentucky. Our Bellaire river terminal, located on the Ohio River in Bellaire, Ohio, has an annual throughput capacity of over 4 million tons with a sustainable barge loading rate of 2,000 tons per hour. The barge harbor for this terminal can simultaneously hold up to 25 loaded barges and 20 empty barges. We control our Bellaire river terminal through a long-term lease agreement with a third party. In May 2010, we signed a new five-year lease, effective January 1, 2010, with three subsequent five-year renewal terms at our option for a total of up to 20 years. We own our Island river terminal and transloading facility that is located on the Green River in western Kentucky. Our Island river terminal has an annual throughput capacity of approximately 3 million tons with a sustainable barge loading rate of 1,300 tons per hour.

Depending on coal quality and customer requirements, in most cases our coal is crushed and shipped directly from our mines to our customers. However, blending different types or grades of coal may be required from time to time to meet the coal quality and specifications of our customers. Coal of various sulfur and ash contents can be mixed or “blended” to meet the specific combustion and environmental needs of customers. Blending is typically done at our six blending facilities:

•

our Barb Tipple blending and coal crushing facility that is adjacent to one of our customer’s power plants near Coshocton, Ohio;

•

our Strasburg wash plant near Strasburg, Ohio;

•

our Bellaire river terminal on the Ohio River;

•

our Island river terminal and transloading facility on the Green River in western Kentucky;

•

our Stonecreek coal crushing facility located in Tuscarawas County, Ohio; and

•

our Schoate wash plant located in Muhlenberg County, Kentucky.

The following map shows the locations of our Northern Appalachia mining operations and coal reserves and related transportation infrastructure.

The following map shows the locations of our Illinois Basin mining operations and coal reserves and related transportation infrastructure.

Northern Appalachia

We operate seven surface mining complexes in Northern Appalachia, substantially all of which are located in eastern Ohio. For the year ended December 31, 2010, our mining complexes in Northern Appalachia produced an aggregate of 5.8 million tons of steam coal. The following table provides summary information regarding our mining complexes in Northern Appalachia as of December 31, 2010 and for the years indicated:

												Tons Produced for the
		Transportation Facilities						Number				Years Ended
		Utilized				Transportation		of Active				December 31,
Mining Complex		River Terminal		Rail Loadout		Method(1)		Mines				2010				2009				2008
												(in millions)
Cadiz (2)		Bellaire		Cadiz		Barge, Rail			3				1.4				1.1				1.4
Tuscarawas County (2)		—		—		Truck			5				0.9				0.9				1.0
Plainfield		—		—		Truck			1				0.3				0.5				0.5
Belmont County		Bellaire		—		Barge			4				1.1				1.3				0.9
New Lexington		—		New Lexington		Rail			1				0.6				0.6				0.7
Harrison(3)		Bellaire		Cadiz		Barge, Rail, Truck			1				1.0				0.7				0.4
Noble County		Bellaire		—		Barge, Truck			2				0.5				0.3				0.2
Total									17				5.8				5.4				5.1

Cadiz Mining Complex. The Cadiz mining complex is located principally in Harrison County, Ohio and includes reserves located in Jefferson County, Ohio and Washington County, Pennsylvania. It consists of the Daron, Elk Run and County Road 29 mines. We began our mining operations at this mining complex in 2000. Operations at the Cadiz mining complex target the Pittsburgh #8, Redstone #8A and Meigs Creek #9 coal seams. As of December 31, 2010, the Cadiz mining complex included 10.9 million tons of proven and probable coal reserves. The infrastructure at this mining complex includes a coal crusher, a truck scale and the Cadiz rail loadout. Coal produced from the Cadiz mining complex is trucked either to our Bellaire river terminal on the Ohio River and then transported by barge to the customer, or trucked to our Cadiz rail loadout facility on the Ohio Central Railroad and then transported by rail to the customer. This mining complex uses area and auger methods of surface mining. This mining complex produced 1.4 million tons of coal for the year ended December 31, 2010.

Tuscarawas County Mining Complex. The Tuscarawas County mining complex is located in Tuscarawas, Columbiana and Stark Counties, Ohio, and consists of the Stonecreek, Stillwater, Chumney, Lisbon and Strasburg mines. We began our mining operations at this mining complex in 2003. Operations at this mining complex target the Brookville #4, Lower Kittanning #5, Middle Kittanning #6, Upper Freeport #7 and Mahoning #7A coal seams. As of December 31, 2010, the Tuscarawas County mining complex included 7.6 million tons of proven and probable coal reserves. The infrastructure at this mining complex includes three coal crushers with truck scales and the Strasburg wash plant. Coal produced from the Tuscarawas County mining complex is trucked directly to our customers, our Barb Tipple blending and coal crushing facility or our Strasburg wash plant. Coal trucked to our Barb Tipple blending and coal crushing facility or our Strasburg wash plant is then transported by truck to the customer after processing is completed. This mining complex uses the area, contour, auger and highwall miner methods of surface mining. This mining complex produced 0.9 million tons of coal for the year ended December 31, 2010.

Plainfield Mining Complex. The Plainfield mining complex is located in Muskingum, Guernsey and Coshocton Counties, Ohio, and consists of the Plainfield mine. We began our mining operations at this mining complex in 1990. Operations at the Plainfield mining complex target the Middle Kittanning #6 coal seam. As of December 31, 2010, the Plainfield mining complex included 6.4 million tons of proven and probable coal reserves. The infrastructure at this mining complex includes our Barb Tipple blending and coal crushing facility. The majority of the coal produced from the Plainfield mining complex is trucked to our Barb Tipple facility for crushing and blending or directly to the customer. Coal trucked to our Barb Tipple facility is transported by truck to the customer after processing is completed. Some of the coal production from this mining complex is trucked to our Strasburg wash plant and then transported by truck to the customer. This mining complex uses contour, auger and highwall miner methods of surface mining. This mining complex produced 0.3 million tons of coal for the year ended December 31, 2010.

Belmont County Mining Complex. The Belmont County mining complex is located in Belmont County, Ohio, and consists of the Lafferty, Flushing, Jeffco and Wheeling Valley mines. We began our mining operations at this mining complex in 1999. Operations at the Belmont County mining complex target the Pittsburgh #8 and Meigs Creek #9 coal seams. As of December 31, 2010, the Belmont County mining complex included 6.2 million tons of proven and probable coal reserves. Coal produced from the Belmont County mining complex is primarily transported by truck to our Bellaire river terminal on the Ohio River. Coal produced from this mining complex is crushed and blended at the Bellaire river terminal before it is loaded onto barges for shipment to our customers on the Ohio River. This mining complex uses area, contour, auger and highwall miner methods of surface mining. This mining complex produced 1.1 million tons of coal for the year ended December 31, 2010.

New Lexington Mining Complex. The New Lexington mining complex is located in Perry, Athens and Morgan Counties, Ohio, and consists of the New Lexington mine. We began our mining operations at this mining complex in 1993. Operations at the New Lexington mining complex target the Lower Kittanning #5, Middle Kittanning #6 and Pittsburgh #8 coal seams. As of December 31, 2010, the New Lexington mining complex included 5.7 million tons of proven and probable coal reserves. The infrastructure at this mining complex includes a coal crusher, a truck scale and the New Lexington rail loadout. Coal produced from the New Lexington mining complex is delivered via-off highway trucks to our New Lexington rail loadout facility on the Ohio Central Railroad where it is then transported by rail to the customer. This mining complex uses the area method of surface mining. This mining complex produced 0.6 million tons of coal for the year ended December 31, 2010.

Harrison Mining Complex. The Harrison mining complex is located in Harrison County, Ohio, and consists of the Harrison mine. Mining operations at this mining complex began in 2007. The Harrison mining complex is owned by Harrison Resources. We own 51.0% of Harrison Resources and CONSOL Energy owns the remaining 49.0% of Harrison Resources indirectly through one of its subsidiaries. We entered into this joint venture in 2007 to mine coal reserves purchased from CONSOL Energy. We manage all of the operations of, and perform all of the contract mining and marketing services for, Harrison Resources. Because the results of operations of Harrison Resources are included in our consolidated financial statements for the year ended December 31, 2010 as required by GAAP, coal production and proven and probable coal reserves attributable to the Harrison mining complex are presented on a gross basis assuming we owned 100.0% of Harrison Resources.

Since its formation in 2007, Harrison Resources has acquired 6.9 million tons of proven and probable coal reserves from CONSOL Energy. We believe that CONSOL Energy controls additional reserves in Harrison County, Ohio that could be acquired by Harrison Resources in the future. However, CONSOL Energy has no obligation to sell those reserves to Harrison Resources, and we have no assurance that Harrison Resources will be able to acquire those reserves from CONSOL Energy on acceptable terms.

Operations at the Harrison mining complex target the Pittsburgh #8, Redstone #8A and Meigs Creek #9 coal seams. As of December 31, 2010, the Harrison mining complex included 5.1 million tons of proven and probable coal reserves. The infrastructure at this mining complex includes a coal crusher and a truck scale. Coal produced from the Harrison mining complex is trucked to our Bellaire river terminal, our Cadiz rail loadout facility or directly to the customer. Coal trucked to our Bellaire river terminal is transported to the customer by barge and coal trucked to our Cadiz rail loadout facility is transported to the customer by rail. This mining complex uses the area method of surface mining. This mining complex produced 1.0 million tons of coal for the year ended December 31, 2010.

Noble County Mining Complex. The Noble County mining complex is located in Noble and Guernsey Counties, Ohio, and consists of the Long-Sears and Hall’s Knob mines. We began our mining operations at this mining complex in 2006. Operations at the Noble County mining complex target the Pittsburgh #8 and Meigs Creek #9 coal seams. As of December 31, 2010, the Noble County mining complex included 2.7 million tons of proven and probable coal reserves. Coal produced from the Noble County mining complex is trucked to our Bellaire river terminal on the Ohio River or to our Barb Tipple facility. Coal trucked to our Bellaire river terminal is then transported by barge to the customer. Coal trucked to our Barb Tipple blending and coal crushing facility is transported by truck to the customer after processing is completed. This mining complex uses the area, contour and auger methods of surface mining. This mining complex produced 0.5 million tons of coal for the year ended December 31, 2010.

Illinois Basin

We operate one surface mining complex in the Illinois Basin, which is located in western Kentucky. For the year ended December 31, 2010, this mining complex produced an aggregate of 1.7 million tons of steam coal. The following table provides summary information regarding our mining complex in the Illinois Basin as of December 31, 2010 and for the year then ended:

Tons Produced for

Transportation

the Year Ended

Facilities Utilized

December 31,

River

Rail

Transportation

Number of

2010

Mining Complex

Terminal

Loadout

Method(1)

Active Mines

(in millions)

Muhlenberg County

Island

—

Barge, Truck

4

1.7

Muhlenberg County Mining Complex. The Muhlenberg County mining complex is located in Muhlenberg and McClean Counties, in western Kentucky, and consists of the Schoate, Highway 431, KO and Rose France mines. We began our mining operations at this mining complex in October 2009. Operations at the Muhlenberg County mining complex target the #5, #6, #9, #10, #11, #12 and #13 coal seams of the Illinois Basin. As of December 31, 2010, the Muhlenberg County mining complex included 23.5 million tons of proven and probable coal reserves. The infrastructure at this mining complex includes the Schoate wash plant, the KO coal crusher, the Rose France coal crusher and our Island river terminal. Coal produced from this mining complex is usually crushed at the mine site and then trucked to our Island river terminal on the Green River or directly to the customer. Coal trucked to our Island river terminal is then transported to the customer by barge. Some of the production from this mining complex is washed at our Schoate wash plant prior to being transported by truck directly to the customer, or by truck to our Island river terminal and then transported by barge to the customer. This mining complex uses the area method of surface mining. This mining complex produced 1.7 million tons of steam coal during the year ended December 31, 2010.

Underground Coal Reserves

We began our underground mining operation at the Tusky mining complex in late 2003 after leasing our underground coal reserves from a third party in exchange for a royalty based on tonnage sold. In June 2005, we sold the Tusky mining complex, and we subleased our underground coal reserves associated with that complex to the purchaser in exchange for an overriding royalty. Our overriding royalty is equal to a percentage of the sales price received by our sublessee for the coal produced from our underground coal reserves. In addition, our sublessee is obligated to pay the royalty we owe to our lessor. We have almost 15 years remaining on the lease for our underground coal reserves, and our sublessee has almost 15 years remaining on its sublease from us.

Reclamation

We are committed to minimizing our environmental impact during the mining process. However, there is always some degree of impact. To minimize the long-term environmental impact of our mining activities, we plan and monitor each phase of our mining projects as well as our post-mining reclamation efforts. As of December 31, 2010, we had approximately $34.9 million in surety bonds and $14,000 in cash bonds outstanding to secure the performance of our reclamation obligations. Additionally, as of December 31, 2010, our surety bonds were supported by approximately $6.7 million in letters of credit. 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 our surety bonds to be released. We perform reclamation activities on a continuous basis as our mining activities progress.

Over 84% of our active surface mining permits are associated with coal reserves that were mined by other coal producers prior to the implementation of the Surface Mining Control & Reclamation Act of 1977, or SMCRA. We are able to economically mine these reserves due to increased coal pricing and improved mining technologies compared to the pre-SMCRA period. Reclamation standards prior to SMCRA were considerably lower than today’s standards. These pre-SMCRA mining areas have unreclaimed highwalls and often have water quality or vegetation deficiencies. Our mining activities not only recover coal that was left behind by previous operators, but also significantly reduce the environmental and safety hazards created by their pre-SMCRA mining activities. Although we have reclamation obligations with respect to these pre-SMCRA mining areas, these obligations are typically no greater than the reclamation obligations for newly mined reserves.

Surface or groundwater that comes in contact with materials resulting from mining activities can become acidic and contain elevated levels of dissolved metals, a condition referred to as Acid Mine Drainage, or AMD. We have seven mining permits that are identified on Ohio’s Inventory of Long-Term AMD sites. Only one of these sites, associated with the Strasburg wash plant, requires continuous AMD treatment, for which we have estimated the present value of the projected annual treatment cost at approximately $85,000 per year. While we anticipate that AMD treatment will not be required once reclamation is completed, it is possible that AMD treatment will be required for some time and current AMD treatment costs could escalate due to changes in flow or water quality. Two sites on the AMD Inventory List have been recommended by Ohio for removal from the AMD Inventory List and the remaining sites are being monitored to assess long-term AMD treatment issues. Moreover, we anticipate that one of these sites being recommended for removal from the AMD Inventory List will receive final surety bond release in 2011.

Limestone

At our Daron and Strasburg mines, we remove limestone in order to mine the underlying coal. We sell this limestone to a third party that crushes and processes the limestone before it is sold to local governmental authorities, construction companies and individuals. The third party pays us for this limestone based on a percentage of the revenue it receives from sales of this limestone. Our revenues for the year ended December 31, 2010 include $1.5 million in limestone sales.

During 2010, we produced 0.4 million tons of limestone. Based on estimates from our internal engineers, our Cadiz mining complex has 7.4 million tons of proven and probable limestone reserves as of December 31, 2010. All of these limestone reserves were assigned reserves, which are limestone reserves that can be recovered without a significant capital expenditure for mine development.

Other Operations

During 2010, we generated $2.2 million of revenue from a variety of services we performed in connection with our surface mining operations. This revenue included the following:

•

service fees we earned for operating a transloader for a third party that offloads coal from railcars on the Ohio Central Railroad at one of our customer’s power plants;

•

service fees we earned for providing earth-moving services for Tunnel Hill Partners, LP, an entity owned by our sponsors that owns a landfill; and

•

service fees we earned for hauling and disposing of ash at a third party landfill for two municipal utilities.

For more information regarding our relationships and our sponsors’ relationships with Tunnel Hill Partners, LP, please read “Certain Relationships and Related Transactions, and Director Independence.”

Customers

General

We market the majority of the coal we produce to base-load power plants in our six-state market area under long-term coal sales contracts. Our primary customers are major electric utilities, municipalities and cooperatives and industrial customers. For the year ended December 31, 2010, we derived 76.3% of our revenues from coal sales to electric utilities (including sales through brokers), 15.7% from coal sales to municipalities and cooperatives, 5.8% from coal sales to industrial customers and the remaining 2.2% from a mixture of sales of non-coal material such as limestone, royalty payments on our underground coal reserves and fees for services we performed for third parties.

Long-Term Coal Sales Contracts

For the past three years over 90.0% of our coal sales were made under long-term coal sales contracts and we intend to continue to enter into long-term coal sales contracts for substantially all of our annual coal production. We believe our long-term coal sales contracts reduce our exposure to fluctuations in the spot price for coal and provide us with a reliable and stable revenue base. Our long-term coal sales contracts also allow us to partially mitigate our exposure to rising costs to the extent those contracts have full or partial cost pass through or cost adjustment provisions.

During 2010, we executed over $275 million in long-term coal sales contracts primarily having an effect on sales beginning in 2012. These contracts, the majority of which were related to our Illinois Basin operations, were executed at prices significantly higher than current levels. For 2011, 2012, 2013 and 2014, we currently have long-term coal sales contracts that represent 100%, 78%, 52% and 47%, respectively, of our 2011 estimated coal sales of 9.1 million tons. Two of our long-term coal sales contracts with the same customer contain provisions that provide for price re-openers. These price re-openers provide for market-based adjustments to the initial contract price every three years. These long-term coal sales contracts will terminate in 2013 if we cannot agree upon a market-based price with the customer prior to the termination date. In addition, we have one long-term coal sales contract with another customer that will terminate in 2014 if we cannot agree upon a market-based price with the customer prior to the termination date. The coal tonnage which is involved for these two customers through 2014 is 1.0 million tons annually for 2013 and 2014 and 0.4 million tons annually for 2014, respectively.

The current term of our long-term coal sales contract with American Electric Power Service Corporation, or AEP, runs through 2012 but it can be extended for two additional three-year terms if AEP gives us six months advance notice of its election to extend the contract. For each extension term, we will negotiate with AEP to agree upon a market-based price based on similar term contracts. In addition, the contract contains substantial cost pass through and cost adjustment provisions. If AEP elects to extend this contract, we will be committed to deliver an additional 2.0 million tons in 2013 and 2014, and our 2013 and 2014 coal sales under long-term coal sales contracts, as a percentage of 2011 estimated coal sales, would increase to 74% and 69%, respectively. We are currently in negotiations with AEP to extend our contract with them. The mutual goal of the parties is to amend the contract to fix the term to run through 2018, establish future pricing that is acceptable to both parties and adjust the amounts of fixed and optional coal tonnage covered by the contract. While the outcome of these negotiations is not certain at this time, we believe that we will be able to achieve an extension that is on amended terms which are beneficial to us and that furthers our long-term coal sales contract strategy.

The terms of our coal sales contracts result from competitive bidding and negotiations with customers. As a result, the terms of these contracts vary by customer. However, most of our long-term coal sales contracts have full or partial cost pass through provisions or cost adjustment provisions. For 2011, 2012, 2013 and 2014, 81%, 96%, 100% and 91% of the coal, respectively, that we have committed to deliver under our current long-term coal sales contracts are subject to full or partial cost pass through provisions. Cost pass through provisions increase or decrease our coal sales price for all or a specified percentage of changes in the costs for such items as fuel, explosives and/or labor. Cost adjustment provisions adjust the initial contract price over the term of the contract either by a specific percentage or a percentage determined by reference to various cost-related indices.

A long-term coal sales contract may contain option provisions that give the customer the right to elect to purchase additional tons of coal each month during the contract term at a fixed price provided for in the contract. For example, upon 30 days advance notice, AEP may elect to purchase, at the contract price in effect at the time for all other tons, an additional 25,000 tons of coal each month under its long-term coal sales contract with us and, in addition, upon 90 days notice, it may elect to purchase, at the contract price in effect at the time for all other tons, an additional 200,000 tons of coal per half year. Our long-term coal sales contracts that provide for these option tons typically require the customer to provide us with from one to three months advance notice of an election to take these option tons. Because the price of these option tons is fixed at the contract price in effect at the time for all other tons under the terms of the contract, if our contract price is below market, we could be obligated to deliver additional coal to those customers at a price that is below the market price for coal on the date the option is exercised. For 2011, 2012, 2013 and 2014, we have outstanding option tons of 0.7 million, 0.9 million, 0.9 million and 1.2 million, respectively. If the customer does elect to receive these option tons, we believe we will have the operating flexibility to meet these requirements through increased production at our mining complexes.

Quality and volumes for the coal are stipulated in our coal sales contracts, and in some instances our customers have the option to vary annual or monthly volumes. Most of our coal sales contracts contain provisions requiring us to deliver coal within certain ranges for specific coal characteristics such as heat content, sulfur, ash, hardness and ash fusion temperature. Some of our coal sales contracts specify approved locations from which coal must be sourced. Failure to meet these specifications can result in economic penalties, suspension or cancellation of shipments or ultimately termination of the contracts. 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 transportation disruptions that affect us as well as unanticipated customer plant outages that may affect the customer’s ability to receive coal deliveries.

Customer Concentration

We derived 92.0% of our total revenues from coal sales to our ten largest customers for the year ended December 31, 2010, with our top five customers accounting for 73.9% of our total revenues. In addition, for the year ended December 31, 2010, we derived 30%, 12%, 11% and 11% of our revenues from AEP, Duke Energy, East Kentucky Power Cooperative and First Energy, respectively.

Transportation

Our coal is delivered to our customers by barge, truck or rail. Over 57% of the coal we shipped during 2010 was transported to our customers by barge, which is generally cheaper than transporting coal by truck or rail. We operate river terminals on the Ohio River in eastern Ohio and the Green River in western Kentucky, which have annual throughput capacities of approximately 4 million tons and 3 million tons, respectively. We also use third-party trucking to transport coal to our customers. In addition, certain of our mines are located near rail lines. On April 1, 2006, we entered into a long-term transportation contract for rail services, which has been amended and extended through March 31, 2011. Our customers typically pay the transportation costs from river terminals, where barges are loaded, to their location. We typically pay for the cost of transporting the coal by rail and/or truck to river terminals, rail loading facilities or directly to our customer’s site(s). However, our sales contracts typically have these transportation costs built into the price, as well as provisions for fuel cost adjustments. For the year ended December 31, 2010, 58%, 40% and 2% of our coal sales tonnage was shipped by barge, truck and rail, respectively.

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

Suppliers

For the year ended December 31, 2010, expenses we incurred to obtain goods and services in support of our mining operations were $130 million, excluding capital expenditures. Principal supplies and services used in our business include diesel fuel, oil, explosives, maintenance and repair parts and services, and tires and lubricants. For the year ended December 31, 2010, we managed our risk from rising fuel prices through both the use of fixed priced forward contracts that provide for physical delivery and the use of escalation and fuel pass through clauses in agreements with key customers. These fixed priced forward contracts have terms ranging from six months to one year and generally do not have collateral requirements.

We use third-party suppliers for a significant portion of our equipment rebuilds and repairs and for blasting services. We use bidding processes to promote competition between suppliers and we seek to develop relationships with those suppliers whose focus is on lowering our costs. We seek suppliers that 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, L.P., Alpha Natural Resources, Inc., Armstrong Coal Company, Buckingham Coal Co., Inc., The Cline Group, CONSOL Energy, Massey Energy Company, Murray Energy Corporation, Patriot Coal Corp., Peabody Energy, Inc. and Rhino Resource Partners LP.

The most important factors on which we compete are coal price, coal quality and characteristics, transportation costs and 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, quality, price and availability of competing sources of fuel such as natural gas, oil and nuclear sources, and alternative energy sources such as hydroelectric power and wind.

Our Safety and Environmental Programs and Procedures

We operate some of the industry’s safest mines. Over the last 5 years, our Mine Safety and Health Administration, or MSHA, reportable incident rate was, on average, 1.9 compared to the national surface mine average of 2.2, or 9.9% lower than the national surface coal mine incident rate. Our safety record can be attributed to our extensive safety program, which includes, among other things, (i) employing two full-time safety professionals, (ii) implementing policies and procedures to protect employees and visitors at our mines, (iii) utilizing experienced third-party blasting professionals to conduct our blasting activities, (iv) requiring a certified surface mine foreman to be in charge of the activities at each mine and (v) ensuring that each employee undergoes the required safety, hazard and task training.

In addition, we remain committed to maintaining a system that seeks to control and reduce the environmental impacts of our mining operations. These controls include, among other things, (i) installing sumps or double walled tanks to contain any spillage of fuel or lubricants at our mines and facilities, (ii) evacuating used oil from equipment and placing it in storage tanks before removing it for proper disposal, (iii) employing four full-time environmental compliance professionals and (iv) utilizing experienced in-house personnel and contractors to conduct extensive pre-mining sampling and studies to comply with environmental laws and regulations.

Mining and Environmental Regulation

Federal, state and local authorities regulate the coal mining industry with respect to environmental, health and safety matters such as employee health and safety, permitting and licensing requirements, air and water pollution, plant and wildlife protection, and the reclamation and restoration of mining properties after mining has been completed. The current laws and regulations have had, and will continue to have, a significant effect on production costs and may impact our competitive advantages. Future laws, regulations or orders, as well as future interpretation and enforcement of current laws, regulations or orders, may substantially increase operating costs, result in delays and disrupt operations, the extent and scope of which cannot be predicted with any degree of certainty. Future laws, regulations or orders may also cause coal to become a less attractive source of energy, thereby reducing its market share as fuel used to generate electricity, which may adversely affect our mining operations or the cost structure or demand for coal.

We endeavor to conduct our mining operations at all times in compliance with all applicable federal, state and local laws and regulations. However, due in part to the complexity and extent of the various regulatory requirements and the nature of coal mining operations, violations can and do occur from time to time.

Mining Permits and Approvals

Numerous federal, state or local governmental permits or approvals are required to conduct coal mining and reclamation operations. The application process can require us to prepare and present data to governmental authorities pertaining to the effect or impact that any proposed production or processing of coal may have upon human health or the environment. The permitting requirements imposed by governmental authorities are costly and have become subject to more enhanced scrutiny, strict review and judicial challenge, which may delay commencement or continuation of mining operations.

In order to obtain federal and state mining permits and approvals, mine operators or applicants must submit a reclamation plan for restoring the mined land to its prior productive or other approved use. Typically, we submit the necessary permit applications 12 to 30 months before we plan to mine a new area. Some required mining permits have become increasingly difficult to obtain in a timely manner or at all, and in some instances we have had to abandon coal in certain areas of the application in order to obtain permit approvals. The application review process has become increasingly longer and has more often been subject to legal challenge by environmentalists and other advocacy groups, although we are not aware of any such challenges to any of our pending permit applications.

Violations of federal, state and local laws or regulations or any permit or approval issued thereunder can result in substantial fines and penalties, including revocation or suspension of mining permits. In certain circumstances, criminal sanctions can be imposed for knowing and willful failure to comply with these laws, regulations, permits or approvals.

Surface Mining Control and Reclamation Act

SMCRA establishes mining, reclamation and environmental protection standards for all aspects of surface coal mining, including the surface effects of underground coal mining. Mining operators must obtain SMCRA permits and permit renewals from the Office of Surface Mining, or the OSM, or from the applicable state agency if the state has obtained primacy. A state may achieve primacy if it develops a regulatory program that is no less stringent than the federal program and is approved by OSM. Our mines are located in Ohio, Pennsylvania, West Virginia and Kentucky, each of which have primacy to administer the SMCRA program.

SMCRA permit provisions include a complex set of requirements, which include, among other things, coal exploration, mine plan development, topsoil or a topsoil removal alternative, storage and replacement, selective handling of overburden materials, mine pit backfilling and grading, disposal of excess spoil, protection of the hydrologic balance, surface runoff and drainage control, establishment of suitable post-mining land uses and re-vegetation. The process of preparing a mining permit application begins by collecting baseline data to adequately characterize the pre-mining environmental conditions of the permit area. This work is typically conducted by third-party consultants with specialized expertise and often includes surveys or assessments of the following: cultural and historical resources, geology, soils, vegetation, aquatic organisms, wildlife, potential for threatened, endangered or other special status species, surface and groundwater hydrology, climatology, riverine and riparian habitat and wetlands. The geologic data and information derived from the other surveys or assessments are used to develop the mining and reclamation plans presented in the permit application. The mining and reclamation plans address the provisions and performance standards of the state’s equivalent SMCRA regulatory program, and are also used to support applications for other permits or authorizations required to conduct coal mining activities. Also included in the permit application is information used for documenting surface and mineral ownership, variance requests, public road use, bonding information, mining methods, mining phases, other agreements that may relate to coal, other minerals, oil and gas rights, water rights, permitted areas, and ownership and control information required to determine compliance with OSM’s Applicant Violator System, or AVS, including the mining and compliance history of officers, directors and principal owners of the entity.

Once a permit application is prepared and submitted to the regulatory agency, it goes through a completeness and technical review. In addition, before a SMCRA permit is issued, a mine operator must submit a bond or otherwise secure the performance of all reclamation obligations. After the application is submitted, public notice or advertisement of the proposed permit action is required, which is followed by a public comment period. It is not uncommon for this process to take from 12 to 30 months for a SMCRA mine permit application. This variability in time frame for permitting is a function of the discretion vested in the various regulatory authorities’ handling of comments and objections relating to the project received from the governmental agencies involved and the general public. The public also has the right to comment on and otherwise engage in the administrative process including at the public hearing and through judicial challenges to an issued permit.

Federal laws and regulations also provide that a mining permit or modification can be delayed, refused or revoked if owners of specific percentages of ownership interests or controllers (i.e., officers and directors or other entities) of the applicant have, or are affiliated with another entity that has, outstanding violations of SMCRA or state or tribal programs authorized by SMCRA. This condition is often referred to as being “permit blocked” under the AVS. Thus, non-compliance with SMCRA can provide a basis for denying the issuance of new mining permits or modifications of existing mining permits. We are not permit-blocked and know of no existing circumstances which could reasonably provide such a basis for denial.

We have subleased our underground coal reserves at the Tusky mining complex to a third party in exchange for an overriding royalty. Under our sublease, our sublessee is contractually obligated to comply with all federal, state and local laws and regulations, including the reclamation and restoration of the mined areas by grading, shaping and reseeding the soil as required under SMCRA. Regulatory authorities may attempt to assign the SMCRA liabilities of our sublessee to us if it is not financially capable of fulfilling those obligations and it is determined that we “own” or “control” the sublessee’s mining operation. To our knowledge, no such claims have been asserted against us to date. If such claims are ever asserted against us, we will contest them vigorously on the basis that, among other things, receiving an overriding royalty under a sublease does not alone meet the legal or regulatory test of “ownership” or “control” so as to subject us to the SMCRA liabilities of our sublessee.

We maintain coal refuse areas and slurry impoundments at our Tuscarawas County and Muhlenberg County mining complexes. Such areas and impoundments are subject to extensive regulation under SMCRA and other federal and state laws and regulations. One of those impoundments overlies a mined out area, which can pose a heightened risk of structural failure and of damages arising out of such failure. When a slurry impoundment experiences a structural failure, it could release large volumes of coal slurry into the surrounding environment, which in turn can result in extensive damage to the environment and natural resources, such as bodies of water. A failure may also result in civil penalties or criminal fines, personal injuries and property damages, and damage to wildlife or natural resources.

In 1983, the OSM adopted the “stream buffer zone rule,” or SBZ Rule, which prohibited mining disturbances within 100 feet of streams if there would be a negative effect on water quality. In December 2008, the OSM finalized a revised SBZ Rule, which purported to clarify certain aspects of the 1983 SBZ Rule. Several organizations challenged the 2008 revision to the SBZ Rule in two related actions filed in the U.S. District Court for the District of Columbia. In June 2009, the Interior Department and the U.S. Army entered into a memorandum of understanding on how to protect waterways from degradation if the revised SBZ Rule were vacated due to the litigation. In August 2009, the District Court concluded that the revised SBZ Rule could not be vacated without following the Administrative Procedure Act and other related requirements. On November 30, 2009, the OSM published an advanced notice of proposed rulemaking to further revise the SBZ Rule. In a March 2010 settlement with litigation parties, OSM agreed to use its best efforts to adopt a final rule by June 29, 2012. On April 30, 2010, the OSM published a Notice of Intent to prepare an Environmental Impact Statement for a new rule — to be called the Stream Protection Rule — that will evaluate alternatives for revising surface mining rules to better protect streams. The requirements of the revised SBZ Rule, when adopted, will likely be stricter than the prior SBZ Rule to further protect streams from the impacts of surface mining, and may adversely affect our business and operations. In addition, Congress has considered legislation to further restrict the placement of mining material in streams. Such legislation could also have an adverse impact on our business.

In addition to the bond requirement for an active or proposed permit, the Abandoned Mine Land Fund, which was created by SMCRA, imposes a fee on all coal produced. The proceeds of the fee are used to restore mines closed or abandoned prior to SMCRA’s adoption in 1977. The current fee is $0.315 per ton of coal produced from surface mines. In 2010, we recorded $2.2 million of expense in our cost of coal sales related to this fee.

Surety Bonds

State laws require a mine operator to secure the performance of its reclamation obligations required under SMCRA through the use of surety bonds or other approved forms of performance security to cover the costs the state would incur if the mine operator were unable to fulfill its obligations. The cost of surety bonds have fluctuated in recent years, and the market terms of these bonds have generally become more unfavorable to mine operators. These changes in the terms of the bonds have been accompanied at times by a decrease in the number of companies willing to issue surety bonds. Some mine operators have therefore used letters of credit to secure the performance of reclamation obligations. We use letters of credit to secure the performance of a portion of our reclamation obligations.

As of December 31, 2010, we had approximately $34.9 million in surety bonds outstanding to secure the performance of our reclamation obligations, which were supported by approximately $6.7 million in letters of credit. There are no letters of credit outstanding in support of surety bonds issued for the benefit of government agencies.

Mine Safety and Health

Coal mining operations are subject to stringent health and safety standards, including pursuant to the Coal Mine Health and Safety Act of 1969 and the Federal Mine Safety and Health Act of 1977, or the Mine Act. In addition to federal regulatory programs, all of the states in which we operate have programs for mine safety and health regulation and enforcement. Collectively, federal and state safety and health regulation in the coal mining industry is among the most comprehensive systems for protection of employee health and safety affecting any segment of U.S. industry. The Mine Act requires mandatory inspections of surface and underground coal mines and requires the issuance of citations or orders for the violation of a mandatory health and safety standard. A civil penalty must be assessed for each citation or order issued. Serious violations of mandatory health and safety standards may result in the issuance of an order requiring the immediate withdrawal of miners from the mine or shutting down a mine or any section of a mine or any piece of mine equipment. The Mine Act also imposes criminal liability for corporate operators who knowingly or willfully violate a mandatory health and safety standard or order and provides that civil and criminal penalties may be assessed against individual agents, officers and directors who knowingly or willfully violate a mandatory health and safety standard or order. In addition, criminal liability may be imposed against any person for knowingly falsifying records required to be kept under the Mine Act and standards.

In 2006, in response to underground mine accidents, Congress enacted the Mine Improvement and New Emergency Response Act, or MINER Act. The MINER Act imposed additional burdens on coal operators, including (i) emergency response plans that address post-accident communications, tracking of miners, breathable air, lifelines, training and communication with local emergency response personnel, (ii) requirements for mine rescue teams, (iii) prompt notification of federal authorities of incidents that pose a reasonable risk of death and (iv) increased penalties for violations of certain federal laws and regulations. Various states have also increased regulation in many of these areas. In the wake of several underground mine accidents, enforcement scrutiny has also increased, including more inspection hours at mine sites, an increased number of inspections and increased issuance of the number and the severity of enforcement actions. Additional federal and state legislation related to mine safety and health is under consideration. We believe that our compliance with these and other reasonably likely mine health and safety laws and regulations could increase our mining costs.

In 2010, in response to additional underground mine accidents, Congress expanded mine safety disclosure requirements pursuant to Section 1503 of the Dodd-Frank Wall Street Reform and Consumer Act. On December 15, 2010, the SEC issued proposed rules to implement Section 1503 by outlining the way in which mining companies must disclose to investors certain information about mine safety and health standards. In 2010, for each coal mine we operated: the total number of violations of mandatory health or safety standards that could significantly and substantially, or S&S, contribute to the cause and effect of a coal or other mine safety or health hazard under Section 104 of the Mine Act for which we received a citation from MSHA was thirty (30) as shown in the following Table OXF-MSHA-1; the total number of orders issued under Section 104(b) of the Mine Act was zero; the total number of citations and orders for unwarrantable failure to comply with mandatory health or safety standards under Section 104(d) of the Mine Act was zero; the total number of flagrant violations under Section 110(b)(2) of the Mine Act was zero; the total number of imminent danger orders issued under Section 107(a) of the Mine Act was zero; and the total dollar value of the proposed assessments from MSHA under the Mine Act was $19,882. In addition, no coal mine of which we were the operator received written notice from MSHA of a pattern of violations, or the potential to have such a pattern, of mandatory health or safety standards that are of such nature as could have significantly and substantially contributed to the cause and effect of coal or other mine health or safety hazards under Section 104(e) of the Mine Act. The pending legal actions before the Federal Mine Safety and Health Review Commission are shown in the following Table OXF-MSHA-2.

Table: OXF-MSHA-1

																						(F)								(H)
		(A)				(B)				(C)				(D)				(E)				Proposed								Pending
		Section				Section				Section				Section				Section				Assess-				(G)				Legal
Mining Complex		104				104(b)				104(d)				110(b)(2)				107(a)				ments				Fatalities				Action
Cadiz			3				—				—				—				—			$	1,720				—				2
Tuscarawas County			1				—				—				—				—			$	2,682				—				—
Belmont County			2				—				—				—				—			$	1,287				—				—
Plainfield			1				—				—				—				—			$	1,542				—				1
New Lexington			1				—				—				—				—			$	1,268				—				1
Harrison			1				—				—				—				—			$	625				—				—
Noble County			1				—				—				—				—			$	734				—				—
Muhlenberg County			20				—				—				—				—			$	10,024				—				—
Totals			30				—				—				—				—			$	19,882				—				4

Table: OXF-MSHA-2

Docket Number

Proposed

MSHA Mine Name

Civil

Oxford Mine Complex/Name

Citation

Date

Penalty

MSHA ID Number

No.

Issued

Assessment

Status

LAKE 2008-383 Oxford Mining #3 New Lexington/New Lexington 33-04336

7138351

1/9/2008

$

1,400

Petition for civil penalty assessment for a miner not wearing a hard hat outside of the operating cab of his equipment. The Petition was served on June 6, 2008 and timely answered on July 3, 2008. The Commission recently issued a Notice of Hearing for April 26, 2011. Oxford’s prehearing report is due April 12.

LAKE 2009-381-M Oxford Mining #2 Plainfield/Adamsville* 33-04213 *Adamsville mine — reclaimed

7141549 7141550

11/3/2008 11/10/2008

$ $

460 460

Petition for civil penalty assessment for two citations regarding brake lights on mobile equipment. The proposed civil penalty assessment became a final order on January 16, 2009, but the notice of contest was mailed to an incorrect address. A Motion to Reopen the Penalty Assessment was filed on March 19, 2009 and unopposed by the Secretary of Labor. The Commission has approved the Motion, and the matter has been assigned to Administrative Law Judge (ALJ) Barbour pending issuance of a Petition for Penalty Assessment.

LAKE 2010 -576 Snyder Mine Cadiz/County Road 29 33-04414

8017301

8/31/2009

$

946

Petition for civil penalty assessment for a rock truck operator failing to maintain control of the vehicle and crashing into the highwall; the driver sustained a broken leg. The Petition was served on May 5, 2010 and timely answered on June 7, 2010. The case has been assigned to ALJ Harner. The parties conducted a status conference with the ALJ and have engaged in settlement discussions to no avail. The parties have requested that the ALJ set the matter for a hearing.

LAKE 2010-577 Snyder Mine Cadiz/County Road 29 33-04414

8024308

2/3/2010

$

207

Petition for civil penalty assessment for a dump truck that did not give an audible sound when reverse was engaged when tested. The Petition was served on May 6, 2010 and timely answered on June 7, 2010. The case has been assigned to ALJ Harner. The parties conducted a status conference with the ALJ and have engaged in settlement discussions to no avail. The parties have requested that the ALJ set the matter for a hearing.

Black Lung

Under the Black Lung Benefits Revenue Act of 1977 and the Black Lung Benefits Reform Act of 1977, as amended in 1981, each coal mine operator must pay federal black lung benefits to claimants who are current and former employees and also make payments to a trust fund for the payment of benefits and medical expenses to claimants who last worked in the coal industry prior to January 1, 1970. The trust fund is funded by an excise tax on production of up to $1.10 per ton for deep-mined coal and up to $0.55 per ton for surface-mined coal, neither amount to exceed 4.4% of the gross sales price. The excise tax does not apply to coal shipped outside the United States. During 2010, we recorded $3.9 million of expense in our cost of coal sales related to this excise tax. The Patient Protection and Affordable Health Choices Act, or PPAHCA, which was enacted on March 23, 2010, made two potentially significant changes to the federal Black Lung program. First, the PPAHCA provides an automatic survivor benefit paid upon the death of a miner with an awarded black lung claim, without requiring proof that the death was due to pneumoconiosis. Second, the PPAHCA establishes a rebuttable presumption with regard to pneumoconiosis among miners with 15 or more years of coal mine employment that are totally disabled by a respiratory condition. These changes could have a material impact on our costs expended in association with the federal black lung program. In addition, we are liable under various state laws for black lung claims.

Clean Air Act

The Clean Air Act and similar state laws affect coal mining operations both directly and indirectly. Direct impacts on coal mining and processing operations include Clean Air Act permitting requirements and control requirements for particulate matter, which includes fugitive dust from roadways, parking lots, and equipment such as conveyors and storage piles.

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

The Clean Air Act indirectly affects coal mining operations by extensively regulating air emissions from coal-fired power plants, which are the largest end users of our coal. Coal contains certain impurities, including sulfur, mercury, chlorine and other constituents, many of which are emitted into the air when coal is burned, including emissions of particulate matter, sulfur dioxide (also referred to as SO2), nitrogen oxides (also referred to as NOx), carbon monoxide, ozone, mercury and other compounds emitted by coal-fired power plants. As a result of the regulation of these emissions, coal-fired power plants, which are the largest end users of our coal, have expended considerable resources, and may be required to expend additional resources, to install emission control equipment or take other steps to lower emissions or otherwise achieve compliance. More stringent regulation by the EPA, states or Congress, pursuant to an international treaty or due to a judicial decision, could make it more costly to operate coal-fired power plants. As a result, coal could become a less attractive and less competitive fuel and future demand could decrease. Although we are unable to predict the magnitude of any impact with any reasonable degree of certainty, reduced demand could reduce the price of coal that we mine and sell, thereby reducing our revenues, and thus could have a material adverse effect on our business and the results of our operations.

In addition to the greenhouse gas regulations discussed below, air emission control programs that affect our operations, directly or indirectly, include, but are not limited to, the following:

•

Acid Rain. The EPA’s Acid Rain Program, in Title IV of the Clean Air Act, regulates SO2 emissions by coal-fired power plants with a generating capacity greater than 25 megawatts. Affected facilities purchase or are otherwise allocated allowances for SO2 emissions. Affected facilities have reduced SO2 emissions by switching to lower sulfur fuels, installing pollution control devices, reducing electricity generating levels or purchasing or trading allowances.

•

SO2. Pursuant to the Clean Air Act, the EPA sets standards, known as National Ambient Air Quality Standards, or NAAQS, for certain pollutants. On June 3, 2010, the EPA issued a stricter NAAQS for SO2 emissions that established a 1-hour standard at a level of 75 parts per billion or ppb to protect against short-term exposure and minimize health-based risks. The EPA indicated that it would abolish the previous annual standard for SO2. Under the new rule, monitors must be set up by 2013 in the areas of the highest concentrations of SO2. Non-attainment decisions will be made by June 2012, state implementation plans will be due by the winter of 2014 and attainment of the standards must be achieved by the summer of 2018.

•

Particulate Matter. Areas that are not in compliance, known as non-attainment areas, with these standards must take steps to reduce emissions levels. Although our operations are not currently located in non-attainment areas, if any of the areas in which we operate become designated as non-attainment areas for particulate matter, our mining operations may be directly affected by any related NAAQS.

•

Ozone. The EPA’s ozone NAAQS imposes stringent limits on NOx emissions, which are classified as an ozone precursor. In July 2009, the U.S. Court of Appeals for the District of Columbia vacated part of a rule implementing the ozone NAAQS and remanded certain other aspects of the rule to the EPA for further consideration. The EPA has proposed a stricter NAAQS for ozone, which it expects to finalize in July 2011. Related non-attainment decisions will be made by July 2013, state implementation plans will be due by the end of 2016 and attainment of the standards must be achieved by 2018 or later, depending on the severity of non-attainment.

•

NOx SIP Call. The NOx SIP Call program was established by the EPA to reduce the transport of nitrogen oxide and ozone on prevailing winds from the Midwest and South to states in the Northeast that alleged they could not meet federal air quality standards because of NOx emissions. As a result of this program, many power plants have been or will be required to install additional emission control measures, such as selective catalytic reduction, or SCR, devices.

•

Clean Air Interstate Rule or CAIR. The EPA’s CAIR calls for power plants in 28 eastern states and the District of Columbia to reduce emission levels of SO2 and NOx pursuant to a cap and trade program similar to the system now in effect for acid rain. In July 2008, the U.S. Court of Appeals for the District of Columbia Circuit vacated the EPA’s CAIR in its entirety and directed the EPA to commence new rule-making. After a petition for rehearing, the court ruled in December 2008 that to completely vacate CAIR would sacrifice public health and environmental benefits and that CAIR should remain in effect while the EPA modifies the rule. The EPA proposed a replacement rule known as the Clean Air Transport Rule in July 2010 that would set state level caps on SO2 and NOx emissions for power plants for 31 eastern states and the District of Columbia. The final rule is expected in July 2011. Under either CAIR or the Clean Air Transport Rule, some coal-fired power plants may be required to install additional pollution control equipment and burn less high sulfur coal.

•

Mercury. In February 2008, the U.S. Court of Appeals for the District of Columbia Circuit vacated the EPA’s Clean Air Mercury Rule, or CAMR, which had established a cap and trade program to reduce mercury emissions from power plants. The EPA is under a court deadline to issue a final rule by November 2011, and will likely impose stricter limitations on mercury emissions from power plants than the vacated CAMR. In the meantime, case-by-case MACT determinations for mercury may be required for new and reconstructed coal-fired power plants. Mercury emissions from coal-fired power plants may also be subject to state regulation, and related federal legislation has been proposed. In addition, in February 2011, the EPA established new MACT for several classes of boilers and process heaters, including large coal-fired boilers and process heaters, which would require significant reductions in the emission of particulate matter, carbon monoxide, hydrogen chloride, dioxins and mercury. The Obama Administration has also indicated a desire to negotiate an international treaty to reduce mercury pollution.

•

Regional Haze. The EPA’s regional haze program seeks to protect and improve visibility at and around national parks, national wilderness areas and international parks. The program may restrict emissions on new coal-fired power plants whose operation may impair visibility at and near such federally protected areas. The program may also require certain existing coal-fired power plants to install additional control measures designed to limit certain haze-causing emissions. On January 19, 2011, several environmental groups notified the EPA that they intend to sue under the citizen suit provision of the Clean Air Act for failure to enforce the regional haze rule.

•

New Source Review, or NSR. A number of pending regulatory changes and court actions by the EPA and various environmental groups may affect the scope of the EPA’s NSR program, which, among other emission sources, requires new coal-fired power plants to install emission control equipment and may require existing coal-fired power plants to install additional emission control equipment. The changes to the NSR program may impact demand for coal nationally, but we are unable to predict the magnitude of any such impact with any reasonable degree of certainty.

Climate Change

Combustion of fossil fuels, such as the coal we produce, results in the emission of carbon dioxide and other greenhouse gases which have been subject to public and regulatory concern with respect to climate change or global warming. Current and future regulation of greenhouse gases may occur on various international, federal, state and local levels, including pursuant to future legislative action, EPA enforcement under the existing Clean Air Act, regional and state laws and initiatives and court orders. The Kyoto Protocol, which expires in 2012, established a set of emission targets for greenhouse gases for ratifying countries. Although it has not ratified the Kyoto Protocol, the United States is participating in international renewal discussions. Any replacement treaty or other international arrangement related to greenhouse gas emissions will have a potentially significant impact on the demand for coal if adopted by the United States.

Congress has actively considered proposals in the past several years to reduce greenhouse gas emissions, mandate electricity suppliers to use renewable energy sources to generate a certain percentage of power, promote the use of clean energy and require energy efficiency measures. Although no bills to reduce such emissions have yet to pass both houses of Congress, bills to reduce such emissions remain pending and others are likely to be introduced. Enactment of comprehensive climate change legislation could impact the demand for coal. Any reduction in the amount of coal consumed by North American electric power generators could reduce the price of coal that we mine and sell, thereby reducing our revenues and have a material adverse effect on our business and the results of our operations.

The EPA has also begun regulating greenhouse gas emissions under the Clean Air Act after authorizion by its December 2009 endangerment finding made in response to the 2007 U.S. Supreme Court Massachusetts v. EPA ruling In May 2010, the EPA issued a “tailoring rule” that determines which stationary sources of greenhouse emissions need to obtain a construction or operating permit, and install best available control technology for greenhouse gas emissions, under the Clean Air Act when such facilities are built or significantly modified. Prior to this rule, permits would have been required for stationary sources with emissions that exceed either 100 or 250 tons per year (depending on the type of source). The tailoring rule increases this threshold for greenhouse gas emissions to 75,000 tons per year on January 1, 2011 with the intent to tailor the requirement to initially apply only to large stationary sources such as coal-fired power plants and large industrial plants. The rule will further modify the threshold after July 1, 2011. In addition, the tailoring rule requires the EPA to undertake another rulemaking by no later than July 1, 2012 to, among other things, consider expanding permitting requirements to sources with greenhouse gas emissions greater than 50,000 tons per year. Moreover, in October 2009, the EPA issued a final rule requiring certain emitters of greenhouse gases, including coal-fired power plants, to monitor and report their annual greenhouse gas emissions to the EPA beginning in 2011 for emissions occurring in 2010. Future federal legislative action or judicial decisions to pending or future court challenges may change any of the foregoing final or proposed EPA findings and regulations. If carbon dioxide emissions from electric utilities were to become subject to additional emission limits or permitting requirements, our customers demand for coal could decrease.

In some areas, carbon dioxide emissions are subject to state and regional regulation. For example, the Regional Greenhouse Gas Initiative, or RGGI, calls for a significant reduction of carbon dioxide emissions from power plants in the participating northeastern states by 2018. The RGGI program calls for signatory states to stabilize carbon dioxide emissions to current levels from 2009 to 2015, followed by a 2.5% reduction each year from 2015 through 2018. Since its inception, several additional northeastern states and Canadian provinces have joined as participants or observers. RGGI has been holding quarterly carbon dioxide allowance auctions for its initial three-year compliance period from January 1, 2009 to December 31, 2011 to allow utilities to buy allowances to cover their carbon dioxide emissions. Other current and proposed greenhouse gas regulation include the Midwestern Greenhouse Gas Reduction Accord, the Western Regional Climate Action Initiative and recently enacted legislation and permit requirements in California and other states.

Also, the U.S. Supreme Court recently granted certiorari to review a decision by the U.S. Court of Appeals for the Second Circuit. The Second Circuit had held that state governments and advocacy groups could seek injunctive relief using certain common law nuisance and trespass theories on the basis that emissions of carbon dioxide from specific sources of emissions may have created a public nuisance. The U.S. Court of Appeals for the Fifth Circuit recently dismissed on procedural grounds a class action in which the plaintiffs had claimed that various oil and energy companies had contributed to climate change.

In addition to direct regulation of greenhouse gases, over 30 states have adopted mandatory “renewable portfolio standards,” which require electric utilities to obtain a certain percentage of their electric generation portfolio from renewable resources. These standards generally range from 10% to 30% over time periods that extend from the present until between 2020 and 2030. Several other states have renewable portfolio standard goals that are not yet legal requirements. Other states may adopt similar requirements, and federal legislation is a possibility in this area. To the extent these requirements affect our current and prospective customers, they may reduce the demand for coal-fired power, and may affect long-term demand for our coal.

These and other current or future climate change rules, court orders or other legally enforceable mechanisms may require additional controls on coal-fired power plants and industrial boilers and may cause some users of coal to switch from coal to lower carbon dioxide emitting fuels or shut down coal-fired power plants. Reasonably likely future regulation may include a carbon dioxide cap and trade program, a carbon tax or other regulatory regimes. The cost of future compliance may also depend on the likelihood that cost effective carbon capture and storage technology can be developed by the necessary date. The permitting of new coal-fired power plants has also recently been contested by regulators and environmental organizations based on concerns relating to greenhouse gas emissions. Increased efforts to control greenhouse gas emissions could result in reduced demand for coal. If mandatory restrictions on carbon dioxide emissions are imposed, the ability to capture and store large volumes of carbon dioxide emissions from coal-fired power plants may be a key mitigation technology to achieve emissions reductions while meeting projected energy demands.

Clean Water Act

The Clean Water Act, or CWA, and corresponding state and local laws and regulations affect coal mining operations by restricting the discharge of pollutants, including the discharge of dredged or fill materials, into waters of the United States. The CWA and associated state and federal regulations are complex and frequently subject to amendments, legal challenges and changes in implementation. Recent state and federal court decisions, regulatory actions and proposed legislation have created uncertainty over CWA jurisdiction and permitting requirements that could increase the cost and time we expend on CWA compliance.

CWA and similar state requirements that may directly or indirectly affect our operations include, but are not limited to, the following:

•

Wastewater Discharge. Section 402 of the CWA regulates the discharge of “pollutants” into navigable waters of the United States. The National Pollutant Discharge Elimination System, or NPDES, requires a permit for any such discharge and entails regular monitoring, reporting and compliance with performance standards that govern discharges. Failures to comply with the CWA or the NPDES permits can lead to the imposition of penalties, compliance costs and delays in coal production.

The CWA and corresponding state laws also protect waters that states have designated for special protections including those designated as: impaired (i.e., as not meeting present water quality standards) through total maximum daily load regulations; and “high quality/exceptional use” streams through anti-degradation regulations which restrict or prohibit discharges that result in degradation. Other requirements necessitate the treatment of discharges from coal mining properties for non-traditional pollutants, such as chlorides, selenium and dissolved solids; and “protecting” streams, wetlands, other regulated water sources and associated riparian lands from surface mining and the surface impacts of underground mining. Individually and collectively, these requirements may cause us to incur significant additional costs that could adversely affect our operating results, financial condition and cash flows.

•

Dredge and Fill Permits. Many mining activities, including the development of settling ponds and other impoundments, require a permit issued under authority of Section 404 of the CWA (Section 404 permit(s)) from the Army Corps of Engineers, or Corps, prior to conducting such mining activities where they involve discharges of “fill” into navigable waters of the United States. The Corps is empowered to issue a “nationwide” permit, or NWP, for categories of similar filling activities that are determined to have minimal environmental adverse effects in order to save the cost and time of issuing individual permits under Section 404 of the CWA. Using this authority, the Corps issued NWP 21, which authorizes the disposal of dredge-and-fill material from mining activities into the waters of the United States. Individual Section 404 permits are required for activities determined to have more significant impacts to waters of the United States.

Since 2003, environmental groups have pursued litigation primarily in West Virginia and Kentucky challenging the validity of NWP 21 and various individual Section 404 permits authorizing valley fills associated with surface coal mining operations (primarily mountain-top removal operations). This litigation has resulted in delays in obtaining these permits and has increased permitting costs. The most recent major decision in this line of litigation is the opinion of the U.S. Court of Appeals for the Fourth Circuit in Ohio Valley Environmental Council v. Aracoma Coal Company, 556 F.3d 177 (2009) (Aracoma), issued on February 13, 2009. In Aracoma, the Fourth Circuit rejected the substantive challenges to the Section 404 permits involved in the case primarily by deferring to the expertise of the Corps in review of the permit applications. On August 19, 2010, the U.S. Supreme Court dismissed the then pending certiorari.

After the Fourth Circuit’s Aracoma decision, however, the EPA undertook several initiatives to address the issuance of Section 404 permits for coal mining activities in the Eastern U.S. First, the EPA began to comment on Section 404 permit applications pending before the Corps raising many of the same issues that had been decided in favor of the coal industry in Aracoma. Many of the EPA’s comment letters were submitted long after the end of the EPA’s comment period based on what the EPA contended was “new” information on the impacts of valley fills on stream water quality immediately downstream of valley fills. These letters have created regulatory uncertainty regarding the issuance of Section 404 permits for coal mining operations and have substantially expanded the time required for issuance of these permits.

In June 2009, the Corps, the EPA and the Department of the Interior announced an interagency action plan for an “enhanced review” of any project that requires both a SMCRA permit and a CWA permit designed to reduce the harmful environmental consequences of mountain-top mining in the Appalachian region. As part of this interagency memorandum of understanding, the Corps proposed to suspend and modify NWP 21 in the Appalachian region of Kentucky, Ohio, Pennsylvania, Tennessee, Virginia and West Virginia to prohibit its use to authorize discharges of fill material into waters of the United States for mountain-top mining.

On June 17, 2010, the Corps announced the suspension of the NWP 21 permitting process in these six states until the Corps takes further action on NWP 21, or until NWP 21 expires on March 18, 2012. While the suspension is in effect, proposed surface coal mining projects in these states that involve discharges of dredged or fill material into waters of the United States will have to obtain individual permits from the Corps pursuant to the CWA. Projects currently permitted under NWP 21 are not affected by the suspension, and NWP 21 remains available for proposed surface coal mining projects in other states.

The EPA is also taking a more active role in its review of NPDES permit applications for coal mining operations in Appalachia, and announced in September 2009 that it was delaying the issuance of 74 Section 404 permits in central Appalachia. The EPA’s review has a strong focus in West Virginia, where the EPA plans to review all applications for NPDES permits even though the State of West Virginia is authorized to issue NPDES permits. These initiatives have extended the time required to obtain permits for coal mining and we anticipate further delays in obtaining permits and that the costs associated with obtaining and complying with those permits will increase substantially. Additionally, while it is unknown precisely what other future changes will be implemented as a result of the interagency action plan, any future changes could further restrict our ability to obtain other new permits or to maintain existing permits. Moreover, on April 1, 2010, the EPA issued interim final guidance substantially revising the environmental review of CWA permits by state and federal agencies.

The EPA’s enhanced scrutiny initiatives have been challenged in federal courts by the National Mining Association, or NMA, and the State of West Virginia, and the Kentucky Coal Association/Commonwealth of Kentucky. On January 14, 2011, the U.S. District Court for the District of Columbia denied the EPA’s motion to dismiss the NMA’s complaint and the NMA’s motion for a preliminary injunction of the EPA’s enhanced scrutiny initiatives. The court ruling held that the EPA’s actions “are legislative rules that were adopted in violation of notice and comment requirements.” Although the NMA’s motion for a preliminary injunction was denied, the opinion contains holdings suggesting that the court may rule in favor of the NMA on the merits of the case. The West Virginia and Kentucky cases have been joined with the NMA’s case in the D.C. District Court of Appeals. Unless the challenge to the EPA’s enhanced scrutiny of permit applications is successful, we anticipate that we may not be able to obtain some Section 404 permits, it will continue to take longer to obtain most Section 404 permits, and the costs of obtaining Section 404 permits and compliance with Section 404 permit conditions will increase significantly.

Resource Conservation and Recovery Act

The Resource Conservation and Recovery Act, or RCRA, regulates the management of hazardous wastes from the point of generation through treatment of disposal. RCRA does not apply to most of the wastes generated at coal mines, overburden and coal cleaning wastes, because they are not considered hazardous wastes as EPA applies that term. Only a small portion of the total amount of wastes generated at a mine are regulated as hazardous wastes.

Although RCRA has the potential to apply to wastes from the combustion of coal, the EPA determined that coal combustion wastes do not warrant regulation as hazardous wastes under RCRA in May 2000. Most state solid waste laws also regulate coal combustion wastes as non-hazardous wastes. The EPA is currently considering what type of waste regulations under RCRA are warranted for certain wastes generated from coal combustion, such as coal ash, when used as mine-fill. In June 2009, the EPA released proposals to regulate coal ash as either a non-hazardous waste under Subtitle D of RCRA or as a special waste under Subtitle C of RCRA. If re-classified as hazardous waste, regulations may impose restrictions on ash disposal, provide specifications for storage facilities, require groundwater testing and impose restrictions on storage locations, which could increase our customers’ operating costs and potentially reduce their ability to purchase coal. In addition, contamination caused by the past disposal of coal combustion byproducts, including coal ash, can lead to material liability to our customers under RCRA or other federal or state laws and potentially reduce the demand for coal. The EPA issued a proposed rule for the safe disposal and management of coal ash from coal-fired power plants in May 2010 and received more than 400,000 comments.

Comprehensive Environmental Response, Compensation and Liability Act

The Comprehensive Environmental Response, Compensation and Liability Act, CERCLA or Superfund, and similar state laws affect coal mining operations by, among other things, imposing cleanup requirements for threatened or actual releases of hazardous substances. Under CERCLA and similar state laws, joint and several liability may be imposed on waste generators, site owners, lessees and others regardless of fault or the legality of the original disposal activity. Although the EPA excludes most wastes generated by coal mining and processing operations from the hazardous waste laws, such wastes can, in certain circumstances, constitute hazardous substances for the purposes of CERCLA. In addition, the disposal, release or spilling of some products used by coal companies in operations, such as chemicals, could trigger the liability provisions of CERCLA or similar state laws. Thus, we may be subject to liability under CERCLA and similar state laws for coal mines that we currently own, lease or operate or that we or our predecessors have previously owned, leased or operated, and sites to which we or our predecessors sent waste materials. This includes the Tusky mining complex where we have subleased our underground coal reserves to a third party in exchange for an overriding royalty. We may be liable under CERCLA or similar state laws for the cleanup of hazardous substance contamination and natural resource damages at sites where we own surface rights.

Endangered Species Act

The Endangered Species Act, or ESA, and counterpart state legislation protect species threatened with possible extinction. The U.S. Fish and Wildlife Service, or USFWS, works closely with the OSM and state regulatory agencies to ensure that species subject to the ESA are protected from mining-related impacts. A number of species indigenous to the areas in which we operate, specifically the Indiana bat, are protected under the ESA, and compliance with ESA requirements could have the effect of prohibiting or delaying us from obtaining mining permits. These requirements may also include restrictions on timber harvesting, road building and other mining or agricultural activities in areas containing the affected species or their habitats. Should more stringent protective measures be applied, this could result in increased operating costs, heightened difficulty in obtaining future mining permits, or the need to implement additional mitigation measures.

Use of Explosives

We use third party contractors for blasting services and our surface mining operations are subject to numerous regulations relating to blasting activities. Pursuant to these regulations, we incur costs to design and implement blast schedules and to conduct pre-blast surveys and blast monitoring. In addition, the storage of explosives is subject to regulatory requirements. We presently do not engage in blasting activities. All of our blasting activities are conducted by independent contractors that use certified blasters.

Other Environmental Laws and Matters

We are required to comply with numerous other federal, state and local environmental laws and regulations in addition to those previously discussed, including the Safe Drinking Water Act, the Toxic Substance Control Act and the Emergency Planning and Community Right-to-Know Act.

Employees

To carry out our operations, our general partner employed approximately 836 full-time employees as of December 31, 2010. None of these employees are subject to collective bargaining agreements or are members of any unions. We believe that we have good relations with these employees, and we continually seek their input with respect to our operations. Since our inception, we have had no history of work stoppages or union organizing campaigns.

Available Information

We file annual and quarterly financial reports and current-event reports, as well as interim updates of a material nature to investors, with the SEC. You may read and copy any of these materials at the SEC’s Public Reference Room at 100 F. Street, NE, Washington, DC 20549. Information on the operation of the Public Reference Room is available by calling the SEC at 1-800-SEC-0330. Alternatively, the SEC maintains an Internet site that contains reports, proxy and information statements, and other information regarding issuers that file electronically with the SEC. The address of that site is http://www.sec.gov.

We make our SEC filings available to the public, free of charge and as soon as practicable after they are filed with the SEC, through our Internet website located at http://www.OxfordResources.com. Our annual reports are filed on Form 10-K, our quarterly reports are filed on Form 10-Q, and current-event reports are filed on Form 8-K; we also file amendments to reports filed or furnished pursuant to the Securities Exchange Act of 1934, or the Exchange Act. References to our website addressed in this Annual Report on Form 10-K are provided as a convenience and do not constitute, and should not be viewed as, an incorporation by reference of the information contained on, or available through, the website. Therefore, such information should not be considered part of this Annual Report on Form 10-K.

ITEM 1A.		RISK FACTORS

Risks Related to Our Business

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

In order to pay the minimum quarterly distribution of $0.4375 per unit per quarter, or $1.75 per unit per year, we will require available cash of approximately $9.2 million per quarter, or $36.8 million per year, based on the number of general partner units, common units and subordinated units outstanding at December 31, 2010. 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 production and coal sales and the amount of revenue we generate;

•

the level of our operating costs, including reimbursement of expenses to our general partner;

•

changes in governmental regulation of the mining industry or the electric power industry and the increased costs of complying with those changes;

•

our ability to obtain, renew and maintain permits on a timely basis;

•

prevailing economic and market conditions; and

•

difficulties in collecting our receivables because of credit or financial problems of major customers.

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;

•

fluctuations in our working capital needs;

•

our ability to borrow funds and access capital markets; and

•

the amount of cash reserves established by our general partner.

Because of these and other factors, we may not have sufficient available cash to pay a specific level of cash distributions to our unitholders. Furthermore, the amount of cash we have available for distribution depends primarily upon our cash flow, including cash flow from financial reserves and working capital borrowings, and is not solely a function of profitability, which will be affected by non-cash items. As a result, we may make cash distributions during periods when we record net losses and may be unable to make cash distributions during periods when we record net income.

Decreases in demand for electricity and changes in coal consumption patterns of U.S. electric power generators could adversely affect our business.

Our business is closely linked to domestic demand for electricity and any changes in coal consumption by U.S. electric power generators would likely impact our business over the long term. In 2010 we sold approximately 76.3% of our coal to domestic electric power generators, and we have long-term contracts in place with these electric power generators for a significant portion of our future production. The amount of coal consumed by electric power generation is affected by, among other things:

	•		general economic conditions, particularly those affecting industrial electric power demand, such as the recent downturn in the U.S. economy and financial markets;
	•		indirect competition from alternative fuel sources for power generation, such as natural gas, fuel oil, nuclear, hydroelectric, wind and solar power, and the location, availability, quality and price of those alternative fuel sources;

•

environmental and other governmental regulations, including those impacting coal-fired power plants; and

•

energy conservation efforts and related governmental policies.

According to the EIA, total electricity consumption in the United States fell by approximately 3.8% during 2009 compared with 2008, primarily because of the effect of the economic downturn on industrial electricity demand, and U.S. electric generation from coal fell by approximately 11.0% in 2009 compared with 2008. Further decreases in the demand for electricity, such as decreases that could be caused by a worsening of current economic conditions, a prolonged economic recession or other similar events could have a material adverse effect on the demand for coal and on our business over the long term.

Changes in the coal industry that affect our customers, such as those caused by decreased electricity demand and increased competition, could also adversely affect our business. Indirect competition from gas-fired plants that are cheaper to construct and easier to permit has the most potential to displace a significant amount of coal-fired generation in the near term, particularly older, less efficient coal-powered generators. In addition, uncertainty caused by federal and state regulations could cause coal customers to be uncertain of their coal requirements in future years, which could adversely affect our ability to sell coal to our customers under long-term coal sales contracts.

Our long-term coal sales contracts subject us to renewal risks.

We sell most of the coal we produce under long-term coal sales contracts, which we define as contracts with initial terms of one year or more. As a result, our results of operations are dependent upon the prices we receive for the coal we sell under these contracts. To the extent we are not successful in renewing, extending or renegotiating our long-term contracts on favorable terms, we may have to accept lower prices for the coal we sell or sell reduced quantities of coal in order to secure new sales contracts for our coal.

In addition, we may be adversely affected by extensions of our long-term coal sales contract with AEP if market prices for coal under long-term contracts are low at the time of such extensions or if increases in costs during the term of such extensions are greater than the offsets from our cost pass through and cost adjustment provisions. The current term of our contract with AEP runs through 2012, but it can be extended for two additional three-year terms. For each extension term, the initial contract price will be based upon a market-based price for similar term contracts and will be negotiated at the time of such extension, subject to cost pass through and cost adjustment provisions. The contract also contains option provisions that give AEP the right to purchase additional tons of coal during each extension term at a fixed price. If AEP elects to extend this contract during a period when market prices for coal under similar term contracts are low, then we may be materially and adversely affected if the contract price we are able to negotiate with AEP is lower than our marginal cost of production. Alternatively, we may be materially and adversely affected if our marginal cost of production increases by more than the offsets from our cost pass through and cost adjustment provisions.

Prices and quantities under our long-term coal sales contracts are generally based on expectations of future coal prices at the time the contract is entered into, renewed, extended or re-opened. The expectation of future prices for coal depends upon factors beyond our control, including the following:

•

domestic and foreign supply and demand for coal;

•

domestic demand for electricity, which tends to follow changes in general economic activity;

•

domestic and foreign economic conditions;

•

the price, quantity and quality of other coal available to our customers;

	•		competition for production of electricity from non-coal sources, including the price and availability of alternative fuels and other sources, such as natural gas, fuel oil, nuclear, hydroelectric, wind and solar power, and the effects of technological developments related to these non-coal energy sources;
	•		domestic air emission standards for coal-fired power plants, and the ability of coal-fired power plants to meet these standards by installing scrubbers, purchasing emissions allowances or other means; and

•

legislative and judicial developments, regulatory changes, or changes in energy policy and energy conservation measures that would adversely affect the coal industry.

For more information regarding our long-term coal sales contracts, please read “Item 1. Business — Customers — Long-Term Coal Sales Contracts.”

Our inability to acquire additional coal reserves that are economically recoverable may have a material adverse effect on our future profitability.

Our profitability depends substantially on our ability to mine, in a cost-effective manner, coal reserves that possess the quality characteristics our customers desire. Because our reserves decline as we mine our coal, our future profitability depends upon our ability to acquire additional coal reserves that are economically recoverable to replace the reserves we produce. If we fail to acquire or develop sufficient additional reserves to replace the reserves depleted by our production, our existing reserves will eventually be depleted.

Competition within the coal industry may materially and adversely affect our ability to sell coal at an acceptable price.

We compete for domestic sales with numerous other coal producers in Northern Appalachia and the Illinois Basin and in other coal producing regions of the United States, primarily Central Appalachia and the PRB. The most important factors on which we compete are delivered price (i.e., the cost of coal delivered to the customer, including transportation costs, which are generally paid by our customers either directly or indirectly), coal quality characteristics (primarily heat, sulfur, ash and moisture content) and reliability of supply. Our competitors may have, among other things, greater liquidity, greater access to credit and other financial resources, newer or more efficient equipment, lower cost structures (like our competitors in the PRB), partnerships with transportation companies or more effective risk management policies and procedures. Our failure to compete successfully could have a material adverse effect on our business, financial condition or results of operations.

We depend on a limited number of customers for a significant portion of our revenues, and the loss of, or significant reduction in, purchases by any of them could adversely affect our results of operations and our ability to make cash distributions to our unitholders.

We derived 73.9% of our revenues from coal sales to our five largest customers for the year ended December 31, 2010 and, as of March 1, 2011, we had long-term coal sales contracts in place with these same customers for 78.8% of our 2011 estimated coal sales. We expect to continue to derive a substantial amount of our total revenues from a small number of customers in the future. However, we may be unsuccessful in renewing long-term coal sales contracts with our largest customers, and those customers may discontinue or reduce purchasing coal from us. If any of our largest customers significantly reduces the quantities of coal it purchases from us and if we are unable to sell such excess coal to our other customers on terms substantially similar to the terms under our current long-term coal sales contracts, our business, our results of operations and our ability to make distributions to our unitholders could be adversely affected.

New regulatory requirements limiting greenhouse gas emissions could adversely affect coal-fired power generation and reduce the demand for coal as a fuel source, which could cause the price and quantity of the coal we sell to decline materially.

One major by-product of burning coal is carbon dioxide, which is a greenhouse gas and a source of concern with respect to global warming, also known as climate change. Climate change continues to attract government, public and scientific attention, especially on ways to reduce greenhouse gas emissions, including from coal-fired power plants. Various international, federal, regional and state regulatory initiatives to limit emissions of greenhouse gases include possible future U.S. treaty commitments, new federal or state legislation that may establish a cap-and-trade, and regulation under existing environmental laws by the EPA. Future regulation of greenhouse gas emissions may require additional controls on, or the closure of, coal-fired power plants and industrial boilers and may restrict the construction of new coal-fired power plants.

The permitting of new coal-fired power plants has recently been contested by state regulators and environmental advocacy organizations due to concerns related to greenhouse gas emissions. In addition, a federal appeals courts has allowed a lawsuit pursuing federal common law claims to proceed against certain utilities on the basis that they may have created a public nuisance due to their emissions of carbon dioxide, although the U.S. Supreme Court has granted certiorari to review this decision. A second federal appeals court dismissed such a case on procedural grounds. Future regulation, litigation and permitting related to greenhouse gas emissions may cause some users of coal to switch from coal to a lower-carbon fuel, or otherwise reduce the use of and demand for fossil fuels, particularly coal, which could have a material adverse effect on our business, financial condition or results of operations. For a more detailed discussion of potential climate change impact, please read “Item 1. Business — Mining and Environmental Regulation — Climate Change.”

Existing and future regulatory requirements relating to sulfur dioxide and other air emissions could affect our customers and could reduce the demand for the high-sulfur coal we produce and cause coal prices and sales of our high-sulfur coal to decline materially.

Coal-fired power plants are subject to extensive environmental regulation, particularly with respect to air emissions. For example, the Clean Air Act, and similar state and local laws and related regulations, place annual limits on emissions of sulfur dioxide, particulate matter, nitrogen oxides, mercury and other compounds, including emissions by electric power generators, which are the largest end-users of our coal. The ability of coal-fired power plants to burn the high-sulfur coal we produce may be limited without the use of costly pollution control devices such as scrubbers, the purchase of emission allowances or the blending of our high-sulfur coal with low-sulfur coal.

Projected demand growth for high-sulfur coal in our primary market area is largely dependent on planned installations of scrubbers at new and existing coal-fired power plants that use or plan to use high-sulfur coal as a fuel. The timing and amount of these scrubber installations may be affected by, among other things, anticipated changes in air quality regulations and the price and availability of sulfur dioxide emissions allowances. To the extent that these scrubber installations do not occur or are substantially delayed and sufficient sulfur dioxide allowances are unavailable or are prohibitively expensive, demand for our high-sulfur coal could materially decrease, which could have a material adverse effect on our business, financial condition or results of operations. For a more detailed discussion of the regulation of air emissions, please read “Item 1. Business — Mining and Environmental Regulation — Clean Air Act.”

Our coal mining operations are subject to operating risks, which could result in materially increased operating expenses and decreased production levels and could have a material adverse effect on our business, financial condition or results of operations.

Our coal mining operations are subject to a number of operating risks beyond our control. Because we maintain very limited produced coal inventory, various conditions or events could disrupt operations, adversely affect production and shipments and materially increase the cost of mining and delay or halt production at particular mines for varying lengths of time, which could have a material adverse effect on our business, financial condition or results of operations. These conditions and events include, among others:

•

poor mining conditions resulting from geologic, hydrologic or other conditions, which may cause instability of highwalls or spoil-piles or cause damage to nearby infrastructure;

•

adverse weather and natural disasters, such as heavy rains or flooding;

•

the unavailability of qualified labor and contractors;

•

the unavailability or increased prices of equipment or other critical supplies such as tires and explosives, fuel, lubricants and other consumables;

•

fluctuations in transportation costs and transportation delays or interruptions, including those caused by river flooding and lock closures for repairs;

•

delays, challenges to, and difficulties in acquiring, maintaining or renewing permits or mineral and surface rights;

	•		future health, safety and environmental laws and regulations or changes in the interpretation or enforcement of existing laws and regulations;
	•		mine accidents or other unforeseen casualty events, including those involving injuries or fatalities;

•

increased or unexpected reclamation costs; and

•

the inability to monitor our operations due to failures of information technology systems.

If any of the foregoing changes, conditions or events occurs and is not excusable as a force majeure event, any resulting failure on our part to deliver coal to the purchaser under a long-term sales contracts could result in economic penalties, suspension or cancellation of shipments or ultimately termination of the agreement, any of which could have a material adverse effect on our business, financial condition or results of operations.

We maintain insurance coverage for some but not all potential risks we face. We generally do not carry business interruption insurance and we may elect not to carry other types of insurance in the future. In addition, it is not possible to insure fully against safety, pollution and environmental risks. The occurrence of a significant accident or other event that is not fully covered by insurance could have a material adverse effect on our business, financial condition or results of operations.

In the future, we may not receive cash distributions from Harrison Resources, and Harrison Resources may not be able to acquire additional reserves on economical terms from CONSOL Energy.

In January 2007, we entered into a joint venture, Harrison Resources, with CONSOL Energy. Pursuant to its operating agreement, all members of Harrison Resources must approve cash distributions, other than tax distributions, to its members. The members of Harrison Resources have consistently approved cash distributions from Harrison Resources on a quarterly basis, including an aggregate of $5.9 million in distributions to us during 2010. In the future, however, there can be no assurance that we will receive regular cash distributions from Harrison Resources.

CONSOL Energy controls the vast majority of the additional reserves in Harrison County, Ohio that could be acquired by Harrison Resources in the future. However, CONSOL Energy has no obligation to sell those reserves to Harrison Resources, and we cannot assure you that Harrison Resources could acquire those reserves from CONSOL Energy on acceptable terms. As a result, the growth of, and therefore our ability to receive future distributions from, Harrison Resources may be limited, which could have a material adverse effect on our ability to make cash distributions to our unitholders.

A significant portion of our cash available for distribution to our unitholders is derived from royalty payments we receive on our underground coal reserves, which we do not operate.

In June 2005, we sold our underground mining operations at the Tusky mining complex to an independent coal producer and subleased our underground coal reserves to this producer in exchange for an overriding royalty equal to a percentage of the sales price received for the coal produced and sold. For the year ended December 31, 2010, we received royalty income on our underground coal reserves of approximately $2.8 million or approximately 5.4% of our adjusted EBITDA. The royalty payments we receive could be adversely affected by any of the following:

•

a substantial and extended decline in the sales price for coal produced from our underground coal reserves;

•

any decisions by our sublessee to reduce or discontinue production or sales of coal produced from our underground coal reserves;

•

any failure by our sublessee to properly manage its operations;

•

our sublessee’s operational risks relating to our underground coal reserves, which expose our sublessee to operating conditions and events beyond its control, including the inability to acquire necessary permits, changes or variations in geologic conditions, changes in governmental regulation of the coal industry or the electric power industry, mining and processing equipment failures and unexpected maintenance problems, interruptions due to transportation delays, adverse weather and natural disasters, labor-related interruptions and fires and explosions; and

•

a material decline in the creditworthiness of our sublessee, including as a result of the current economic downturn.

If the royalty payments we receive from our sublessee are reduced, our ability to make cash distributions to our unitholders could be adversely affected.

Increases in the cost of diesel fuel and explosives, or the inability to obtain a sufficient quantity of those supplies, could increase our operating expenses, disrupt or delay our production and have a material adverse effect on our profitability.

We use considerable quantities of diesel fuel in our mining operations. Even though we hedge a portion of our diesel fuel needs, if the price of diesel fuel increases significantly, our operating expenses will increase, which could have a material adverse effect on our profitability. A significant amount of explosives are used in our mining operations. We use third party contractors to provide blasting services, and they generally pass through to us the cost of explosives, which is subject to fluctuations. Additionally, a limited number of suppliers exist for explosives, and any of these suppliers may divert their products to other buyers. Shortages in raw materials used in the manufacturing of explosives or the cancellation of supply contracts under which these raw materials are obtained, could increase the prices and limit the ability of our contractors to obtain these supplies.

Extensive environmental laws and regulations impose significant costs on our mining operations, and future laws and regulations could materially increase those costs or limit our ability to produce and sell coal.

The coal mining industry is subject to increasingly strict federal, state and local environmental and mining safety laws and regulations. The enforcement of laws and regulations governing the coal mining industry has substantially increased, due in part to recent accidents at certain underground mines. Violations can result in administrative, civil and criminal penalties and a range of other possible sanctions. In April 2010, a fatal mining accident in West Virginia received national attention and led Congress to further increase mine safety disclosure requirements. Additional state and national responses increasing mine safety regulation, reporting requirements, inspection and enforcement, particularly with regard to underground mining operations, are possible. New legislation or administrative regulations or new judicial interpretations or administrative enforcement of existing laws and regulations, including proposals related to the protection of the environment that would further regulate and tax the coal industry, may also require us to change operations significantly or incur increased costs and be subject to more adverse consequences for non-compliance. Such changes could have a material adverse effect on our business, financial condition or results of operations.

We may be unable to obtain, maintain or renew permits necessary for our operations, which would materially reduce our production, cash flows and profitability.

As is typical in the coal industry, our coal production is dependent on our ability to obtain various federal and state permits and approvals to mine our coal reserves within the timeline specified in our surface mining plan. The permitting rules, and the interpretations of these rules, are complex, change frequently, and are often subject to discretionary interpretations by regulators, which may increase the costs or possibly preclude the continuance of ongoing mining operations or the development of future mining operations. In addition, the public, including non-governmental organizations, anti-mining groups and individuals, has certain statutory rights to comment upon and otherwise impact the permitting process, including through court intervention. The slowing pace at which necessary permits are issued or renewed for new and existing mines has materially impacted coal production. Permitting by the Corps, the EPA and the Department of the Interior has become subject to enhanced review and stricter enforcement, especially under the CWA, to reduce the harmful environmental consequences of mountain-top mining, especially in Central Appalachia.

Based on our current surface mining plan, we have proven and probable coal reserves with active permits that will allow us to mine for approximately three years. Typically, we submit the necessary permit applications 12 to 30 months before we plan to mine a new area. Some of our required mining permits are becoming increasingly difficult to obtain in a timely manner, or at all, and in some instances we have had to abandon or substantially delay the mining of coal in certain areas covered by the application in order to obtain required permits and approvals. We expect that mining permits will be further delayed in the future if the EPA continues its enhanced review of CWA applications. If the required permits are not issued or renewed in a timely fashion or at all, or if permits issued or renewed are conditioned in a manner that restricts our ability to efficiently and economically conduct our mining activities, we could suffer a material reduction in our production and operations, and there could be a material adverse effect on our ability to make cash distributions to our unitholders. Please read “Item 1. Business — Mining and Environmental Regulation.”

If the assumptions underlying our reclamation and mine closure obligations are materially inaccurate, our costs could be significantly greater than anticipated.

SMCRA and counterpart state laws and regulations establish reclamation and closure standards for surface mining. As of December 31, 2010, we had accrued a reserve of approximately $13.0 million for future reclamation and mine closure obligations. The estimate of ultimate reclamation obligations is reviewed periodically by our management and engineers. Our estimated reclamation and mine closure obligations could change significantly if actual results change from our assumptions, which could have a material adverse effect on our financial condition or results of operations. Please read Note 2 to our consolidated financial statements included elsewhere in this Annual Report on Form 10-K under the heading “Asset Retirement Obligations” for more information regarding our reclamation and mine closure obligations.

Debt we incur in the future may limit our flexibility to obtain financing and to pursue other business opportunities.

Our future level of debt 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;

•

our funds available for operations, future business opportunities and distributions to unitholders will be reduced by that portion of our cash flow required to make interest payments on our debt;

•

we may be more vulnerable to competitive pressures or a downturn in our business or the economy generally; and

•

our flexibility in responding to changing business and economic conditions may be limited.

Our ability to service our debt 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 future indebtedness, we will be forced to take actions such as reducing distributions, reducing or delaying our business activities, acquisitions, investments or capital expenditures, selling assets or seeking additional equity capital. We may not be able to effect any of these actions on satisfactory terms or at all.

Restrictions in our credit facility could adversely affect our business, financial condition, results of operations, ability to make distributions to unitholders and value of our common units.

Our credit facility limits our ability to, among other things:

•

incur additional debt;

•

make distributions on or redeem or repurchase units;

•

make certain investments and acquisitions;

•

incur certain liens or permit them to exist;

•

enter into certain types of transactions with affiliates;

•

merge or consolidate with another company; and

•

transfer or otherwise dispose of assets.

Our credit facility also contains covenants requiring us to maintain certain financial ratios.

The provisions of our credit facility may affect our ability to obtain future financing and pursue attractive business opportunities and our flexibility in planning for, and reacting to, changes in business conditions. In addition, a failure to comply with the provisions of our credit facility could result in a default or an event of default that could enable our lenders to declare the outstanding principal of that debt, together with accrued and unpaid interest, to be immediately due and payable. If the payment of our debt is accelerated, our assets may be insufficient to repay such debt in full, and our unitholders could experience a partial or total loss of their investment.

Our operations may impact the environment or cause environmental contamination, which could result in material liabilities to us.

Our operations use hazardous materials, generate limited quantities of hazardous wastes and may affect runoff or drainage water. In the event of environmental contamination or a release of hazardous materials, we could become subject to claims for toxic torts, natural resource damages and other damages and for the investigation and clean up of soil, surface water, groundwater, and other media, as well as abandoned and closed mines located on property we operate. Such claims may arise out of conditions at sites that we currently own or operate, as well as at sites that we previously owned or operated, or may acquire. Our liability for such claims may be joint and several, so that we may be held responsible for more than our share of the contamination or other damages, or even for the entire share. These and other impacts that our operations may have on the environment, as well as exposures to hazardous substances or wastes associated with our operations, could result in costs and liabilities that could have a material adverse effect on us. Please read “Item 1. Business — Mining and Environmental Regulation.”

We maintain coal refuse areas and slurry impoundments at our Tuscarawas County and Muhlenberg County mining complexes. Such areas and impoundments are subject to extensive regulation. One of those impoundments overlies a mined out area, which can pose a heightened risk of structural failure and of damages arising out of such failure. When a slurry impoundment experiences a structural failure, it could release large volumes of coal slurry into the surrounding environment, which in turn can result in extensive damage to the environment and natural resources, such as bodies of water. A failure may also result in civil or criminal fines, penalties, personal injuries and property damages, and damage to wildlife or natural resources.

Our ability to operate our business effectively could be impaired if we fail to attract and retain key management personnel.

Our ability to operate our business and implement our strategies depends on the continued contributions of Charles C. Ungurean and other executive officers and key employees of our general partner. In particular, we depend significantly on Mr. Ungurean’s long-standing relationships within our industry. The loss of any of our senior executives, and Mr. Ungurean in particular, could have a material adverse effect on our business. In addition, we believe that our future success will depend on our continued ability to attract and retain highly skilled management personnel with coal industry experience and competition for these persons in the coal industry is intense. We may not be able to continue to employ key personnel or attract and retain qualified personnel in the future, and our failure to retain or attract key personnel could have a material adverse effect on our ability to effectively operate our business.

A shortage of skilled labor in the mining industry could reduce labor productivity and increase costs, which could have a material adverse effect on our business and results of operations.

Efficient coal mining using modern techniques and equipment requires skilled laborers in multiple disciplines such as equipment operators, mechanics and engineers, among others. We have from time to time encountered shortages for these types of skilled labor. If we experience shortages of skilled labor in the future, our labor and overall productivity or costs could be materially and adversely affected. If coal prices decrease in the future or our labor prices increase, or if we experience materially increased health and benefit costs with respect to our general partner’s employees, our results of operations could be materially and adversely affected.

Our work force could become unionized in the future, which could adversely affect the stability of our production and materially reduce our profitability.

All of our mines are operated by non-union employees of our general partner. Our employees have the right at any time under the National Labor Relations Act to form or affiliate with a union. If our employees choose to form or affiliate with a union and the terms of a union collective bargaining agreement are significantly different from our current compensation and job assignment arrangements with our employees, these arrangements could adversely affect the stability of our production and materially reduce our profitability.

Inaccuracies in our estimates of our coal reserves could result in lower than expected revenues or higher than expected costs.

Our future performance depends on, among other things, the accuracy of the estimates of our proven and probable coal reserves. There are numerous factors and assumptions inherent in estimating the quantities and qualities of, and costs to mine, coal reserves, any one of which may vary considerably from actual results. These factors and assumptions include:

•

quality of the coal;

•

geologic and mining conditions, which may not be fully identified by available exploration data or may differ from our experiences in areas where we currently mine;

•

the percentage of coal ultimately recoverable;

•

the assumed effects of regulation, including the issuance of required permits, and taxes, including severance and excise taxes and royalties, and other payments to governmental agencies;

•

assumptions concerning the timing for the development of reserves; and

•

assumptions concerning equipment and productivity, future coal prices, operating costs, including for critical supplies such as fuel, tires and explosives, capital expenditures and development and reclamation costs.

As a result, estimates of the quantities and qualities of economically recoverable coal attributable to any particular group of properties, classifications of reserves based on risk of recovery, estimated cost of production, and estimates of future net cash flows expected from these properties as prepared by different engineers and accounting personnel, or by the same engineers and accounting personnel at different times, may vary materially due to changes in the above factors and assumptions. Actual production recovered from identified reserve areas and properties, and revenues and expenditures associated with our mining operations, may vary materially from estimates. Any inaccuracy in the estimates related to our reserves could have a material adverse effect on our ability to make cash distributions.

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

Our ability to receive payment for the coal we sell depends on the continued creditworthiness of our customers. The current economic volatility and tight credit markets increase the risk that we may not be able to collect payments from our customers. A continuation or worsening of current economic conditions or other prolonged global or U.S. recessions could also impact the creditworthiness of our customers.

If the creditworthiness of a customer declines, this would increase the risk that we may not be able to collect payment for all of the coal we sell to that customer. If we determine that a customer is not creditworthy, we may not be required to deliver coal under the customer’s coal sales contract. If we are able to withhold shipments, we may decide to sell the customer’s coal on the spot market, which may be at prices lower than the contract price, or we may be unable to sell the coal at all. Furthermore, the bankruptcy of any of our customers could have a material adverse effect on our financial position. In addition, competition with other coal suppliers could force us to extend credit to customers and on terms that could increase the risk of payment default.

In addition, we sell some of our coal to coal brokers who may resell our coal to end users, including utilities. These coal brokers may have only limited assets, making them less creditworthy than the end users. Under some of these arrangements, we have contractual privity only with the brokers and may not be able to pursue claims against the end users in connection with these sales if we do not receive payment from the broker. In 2010, approximately 24% of our sales were through coal brokers. We expect our sales through coal brokers to increase to approximately 31% of our sales in 2011.

Failure to obtain, maintain or renew our security arrangements, such as surety bonds or letters of credit, in a timely manner and on acceptable terms could have an adverse effect on our ability to make cash distributions to our unitholders.

Federal and state laws require us to secure the performance of certain long-term obligations, such as mine closure or reclamation costs. The amount of these security arrangements is substantial, with total amounts of surety bonds at March 14, 2011 of approximately $35.5 million, which were supported by letters of credit of $6.7 million. Certain business transactions, such as coal leases and other obligations, may also require bonding. Our bonding requirements could increase in the future. We may have difficulty procuring or maintaining our surety bonds. Our bond issuers may demand higher fees, additional collateral, including putting up letters of credit or posting cash collateral, or other terms less favorable to us upon those renewals. Our ability to obtain or renew our surety bonds could be impacted by a variety of other factors including lack of availability, unfavorable market terms, the exercise by third-party surety bond issuers of their right to refuse to renew the surety bonds and restrictions on availability of collateral for current and future third-party surety bond issuers under the terms of any credit arrangements then in place. Due to current economic conditions and the volatility of the financial markets, surety bond providers may be less willing to provide us with surety bonds or maintain existing surety bonds and we may have greater difficulty satisfying the liquidity requirements under our existing surety bond contracts. If we do not maintain sufficient borrowing capacity or have other resources to satisfy our surety and bonding requirements, our operations and our ability to make cash distributions to our unitholders could be adversely affected.

The amount of estimated reserve replacement expenditures that 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.

For 2011, we expect to incur between $5.5 million and $6.0 million in reserve replacement expenditures. Our partnership agreement requires our general partner to deduct from operating surplus each quarter estimated reserve replacement expenditures as opposed to actual reserve replacement expenditures in order to reduce disparities in operating surplus caused by fluctuating reserve replacement costs. This amount is based on our current estimates of the amounts of expenditures we will be required to make in future years to maintain our depleting reserve base, which we believe to be reasonable. In the future our estimated reserve replacement expenditures may be more than our actual reserve replacement expenditures, which will reduce the amount of available cash from operating surplus that we would otherwise have available for distribution to unitholders. The amount of estimated reserve replacement 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, subject to approval by the conflicts committee of the board of directors of our general partner, or the Conflicts Committee.

Our management team does not have experience managing our business as a stand-alone publicly traded partnership, and if they are unable to manage our business as a publicly traded partnership our business may be affected.

Our management team does not have experience managing our business as a publicly traded partnership. If we are unable to manage and operate our partnership as a publicly traded partnership, our business and results of operations will be adversely affected.

We will be required by Section 404 of the Sarbanes-Oxley Act to evaluate the effectiveness of our internal controls. If we are unable to establish and maintain effective internal controls, our financial condition and operating results could be adversely affected.

We are in the process of evaluating our internal controls systems to allow management to report on, and our independent auditors to audit, our internal controls over financial reporting. We are also in the process of performing the system and process evaluation and testing (and any necessary remediation) required to comply with the management report and auditor attestation requirements of Section 404 of the Sarbanes-Oxley Act of 2002. We will be required to comply with Section 404 for the year ending December 31, 2011. However, we cannot be certain as to the timing of completion of our evaluation, testing and remediation actions or the impact of the same on our operations. Furthermore, upon completion of this process, we may identify control deficiencies of varying degrees of severity under applicable SEC and Public Company Accounting Oversight Board rules and regulations that remain unremediated. We will be required to report, among other things, control deficiencies that constitute a “material weakness” or changes in internal controls that, or that are reasonably likely to, materially affect internal controls over financial reporting. A “material weakness” is a deficiency or combination of deficiencies in internal controls over financial reports that results in more than a remote likelihood that a material misstatement of the annual or interim consolidated financial statements will not be prevented or detected.

If we fail to implement the requirements of Section 404 in a timely manner, we might be subject to sanctions or investigation by regulatory authorities such as the SEC. In addition, failure to comply with Section 404 or the report by us of a material weakness may cause investors to lose confidence in our consolidated financial statements, and as a result our unit price may be adversely affected. If we fail to remedy any material weakness, our consolidated financial statements may be inaccurate, we may face restricted access to the capital markets and our unit price may be adversely affected.

Terrorist attacks and threats, escalation of military activity in response to these attacks or acts of war could have a material adverse effect on our business, financial condition or results of operations.

Terrorist attacks and threats, escalation of military activity or acts of war may have significant effects on general economic conditions, fluctuations in consumer confidence and spending and market liquidity, each of which could materially and adversely affect our business. Future terrorist attacks, rumors or threats of war, actual conflicts involving the United States or its allies, or military or trade disruptions affecting our customers may significantly affect our operations and those of our customers. Strategic targets, such as energy-related assets and transportation assets, may be at greater risk of future terrorist attacks than other targets in the United States. Disruption or significant increases in energy prices could result in government-imposed price controls. It is possible that any of these occurrences, or a combination of them, could have a material adverse effect on our business, financial condition and results of operations.

Risks Inherent in an Investment in Us

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

Fiduciary duties owed to our unitholders by our general partner are prescribed by law and the partnership agreement. The Delaware Revised Uniform Limited Partnership Act, or 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:

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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, our unitholders consent to some actions and conflicts of interest that might otherwise constitute a breach of fiduciary or other duties under applicable state law;

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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;

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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 our general partner honestly believed that the decision was in the best interests of the partnership;

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generally provides that affiliated transactions and resolutions of conflicts of interest not approved by the Conflicts Committee and not involving a vote of our 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

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provides that our general partner and its officers and directors will not be liable for monetary damages to us or our limited partners 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.

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

C&T Coal owns an 18.2% limited partner interest in us, AIM Oxford owns a 35.7% limited partner interest in us, and C&T Coal and AIM Oxford own substantially all of and control our general partner and its 2.0% general partner interest in us. 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 C&T Coal and AIM Oxford 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 our unitholders and restricts the remedies available to our unitholders for actions taken by our general partner that might otherwise constitute breaches of fiduciary duty.” The risk to our unitholders due to such conflicts may arise because of the following factors, among others:

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our general partner is allowed to take into account the interests of parties other than us, such as C&T Coal and AIM Oxford, in resolving conflicts of interest, which has the effect of limiting its fiduciary duty to our unitholders;

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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;

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our general partner determines the amount and timing of asset purchases and sales, capital expenditures, borrowings and issuances of additional partnership securities and reserves, each of which can affect the amount of cash that is available for distribution to our unitholders;

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our general partner determines our estimated reserve replacement expenditures, which reduce operating surplus, 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;

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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;

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our general partner determines which costs incurred by it and its affiliates are reimbursable by us;

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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;

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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 80.0% of the common units;
	•		our general partner controls the enforcement of obligations owed to us by it and its affiliates; and

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our general partner decides whether to retain separate counsel, accountants or others to perform services for us.

In addition, AIM currently holds substantial interests in other companies in the energy and natural resource sectors. 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. However, AIM and AIM Oxford are not prohibited from engaging in other businesses or activities, including those that might be in direct competition with us. As a result, they could potentially compete with us for acquisition opportunities and for new business or extensions of the existing services provided by 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 owners. Any such person or entity that becomes aware of a potential transaction, agreement, arrangement or other matter that may be an opportunity for us will not have any duty to communicate or offer such opportunity to us. Any such person or entity will not be liable to us or to any limited partner for breach of any fiduciary duty or other duty by reason of the fact that such person or entity pursues or acquires such opportunity for itself, directs such opportunity to another person or entity or does not communicate such opportunity or information to us. This may create actual and potential conflicts of interest between us and affiliates of our general partner and result in less than favorable treatment of us and our unitholders.

Our 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, our unitholders have only limited voting rights on matters affecting our business and, therefore, limited ability to influence management’s decisions regarding our business. Our unitholders 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 have limited ability to remove our general partner.

Our unitholders are unable to remove our general partner without its consent because affiliates of our general partner own sufficient units to be able to prevent removal of our general partner. The vote of the holders of at least 80.0% of all outstanding common units and subordinated units voting together as a single class is required to remove our general partner. Affiliates of our general partner own 55.4% of our common units and subordinated units. 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 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 our unitholders’ dissatisfaction with our general partner’s performance in managing our partnership will most likely result in the termination of the subordination period.

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 in us 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 our 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 and actions of the board of directors and executive officers of our general partner.

The incentive distribution rights of our general partner may be transferred to a third party without unitholder consent.

Our general partner may transfer its incentive distribution rights to a third party at any time without the consent of our unitholders. If our general partner transfers its incentive distribution rights to a third party but retains its general partner interest, our general partner may not have the same incentive to grow our partnership and increase quarterly distributions to unitholders over time as it would if it had retained ownership of its incentive distribution rights.

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

C&T Coal and AIM Oxford own an aggregate of 55.1% of our common units and subordinated units. If at any time our general partner and its affiliates own more than 80.0% 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. As a result, our unitholders may be required to sell their common units at an undesirable time or price and may not receive any return on their investment. Our unitholders may also incur a tax liability upon a sale of their common 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 limited call right. If our general partner exercised its limited call right, the effect would be to take us private and, if the common units were subsequently deregistered, we would no longer be subject to the reporting requirements of the Exchange Act.

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:

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our unitholders’ proportionate ownership interest in us will decrease;

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the amount of cash available for distribution on each unit may decrease;

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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;

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the relative voting strength of each previously outstanding unit may be diminished; and

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the market price of the common units may decline.

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

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

If our general partner elects to reset the target distribution levels, it will be entitled to receive a number of common units and general partner units. The number of common units to be issued to our general partner will be equal to that number of common units that would have entitled their holder to an average aggregate quarterly cash distribution in the prior two quarters equal to the average of the distributions to our general partner on the incentive distribution rights in the prior two quarters. Our general partner will be issued the number of general partner units necessary to maintain our general partner’s interest in us that existed immediately prior to the reset election. We anticipate that our general partner would exercise this reset right in order to facilitate acquisitions or internal growth projects that would not be sufficiently accretive to cash distributions per common unit without such conversion. It is possible, however, that our general partner could exercise this reset election at a time when it is experiencing, or expects to experience, declines in the cash distributions it receives related to its incentive distribution rights and may, therefore, desire to be issued common units rather than retain the right to receive distributions on its incentive distribution rights based on the initial target distribution levels. As a result, a reset election may cause our common unitholders to experience a reduction in the amount of cash distributions that our common unitholders would have otherwise received had we not issued new common units and general partner units to our general partner in connection with resetting the target distribution levels.

Cost reimbursements due to our general partner and its affiliates 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 our 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 include all costs incurred by our general partner and its affiliates in managing and operating us. We are managed and operated by executive officers and directors of our general partner. The reimbursement of expenses and payment of fees, if any, to our general partner and its affiliates will reduce the amount of cash available for distribution to our unitholders.

Our 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 are not 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 to furnish information about his nationality, citizenship or related status. If a limited partner 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 is not an eligible citizen, the limited partner may be treated as a non-citizen assignee. 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 units 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.

Our unitholders may have liability to repay distributions.

Under certain circumstances, our 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.

Tax Risks

Our tax treatment depends on our status as a partnership for federal income tax purposes. If the Internal Revenue Service, or the IRS, were to treat us as a corporation for federal income tax purposes, which would subject us to 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. A change in our business or a change in current law could cause us to be treated as a corporation for federal income tax purposes or otherwise subject us to taxation as an entity.

If we were treated as a corporation for federal income tax purposes, we would pay federal income tax on our taxable income at the corporate tax rate, which is currently a maximum of 35.0%, and would likely pay state and local income tax at varying rates. Distributions would generally be taxed again as corporate dividends (to the extent of our current and accumulated earnings and profits), 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, if we were treated as a corporation for federal income tax purposes there would be material reduction in the anticipated cash flow and after-tax return to our unitholders, likely causing a substantial reduction in the value of 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 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.

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 U.S. 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. Recently, members of the U.S. Congress considered substantive changes to the existing U.S. federal income tax laws that would have affected the tax treatment of certain publicly traded partnerships. Any modification to the U.S. federal income tax laws or interpretations thereof may or may not be applied retroactively. Although we are unable to predict whether any of these changes or any other proposals will ultimately be enacted, any changes could negatively impact the value of an investment in our common units.

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

Among the changes contained in President Obama’s Budget Proposal for Fiscal Year 2012, or the Budget Proposal, is the elimination of certain key U.S. federal income tax preferences relating to coal exploration and development. The Budget Proposal would: (i) eliminate current deductions, the 60-month amortization period and the 10-year amortization period for exploration and development costs relating to coal and other hard mineral fossil fuels, (ii) repeal the percentage depletion allowance with respect to coal properties, (iii) repeal capital gains treatment of coal and lignite royalties and (iv) exclude from the definition of domestic production gross receipts all gross receipts derived from the sale, exchange, or other disposition of coal, other hard mineral fossil fuels or primary products thereof. The passage of any legislation as a result of the Budget Proposal or any other similar changes in U.S. federal income tax laws could eliminate certain tax deductions that are currently available with respect to coal exploration and development, and any such change could increase the taxable income allocable to our unitholders and negatively impact the value of an investment in our common units.

Our unitholders’ share of our income is taxable to them for U.S. federal income tax purposes even if they do not receive any cash distributions from us.

Because a unitholder is treated as a partner to whom we allocate taxable income which could be different in amount than the cash we distribute, a unitholder’s allocable share of our taxable income is taxable to it, which may require the payment of federal income taxes and, in some cases, state and local income taxes on its share of our taxable income even if it receives no cash distributions from us. Our 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.

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 positions we take, and the IRS’s positions may ultimately be sustained. It may be necessary to resort to administrative or court proceedings to sustain some or all of the positions we take and such positions may not ultimately be sustained. A court may not agree with some or all of the positions we take. Any contest with the IRS, and the outcome of any IRS contest, may have a materially adverse impact on 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 for federal income tax purposes equal to the difference between the amount realized and your tax basis in those common units. Because distributions in excess of your allocable share of our net taxable income decrease your tax basis in your common units, the amount, if any, of such prior excess distributions with respect to the common units you sell will, in effect, become taxable income to you if you sell such common units at a price greater than your tax basis in those common units, even if the price you receive is less than your original cost. Furthermore, a substantial portion of the amount realized on any sale of your common units, 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 common units, you may incur a tax liability in excess of the amount of cash you receive from the sale.

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

Investment in common units by tax-exempt entities, such as employee benefit plans and 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 income tax returns and pay tax on their share of our taxable income. If you are a tax-exempt entity or a non-U.S. person, you should consult a tax advisor before investing in our common units.

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

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

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

We prorate our items of income, gain, loss and deduction for U.S. federal income tax purposes between transferors and transferees of our units each month based upon the ownership of our units on the first day of 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. 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.

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

Because a unitholder whose common units are loaned to a “short seller” to effect a short sale of common units may be considered as having disposed of the loaned common units, he may no longer be treated for federal income tax purposes as a partner with respect to those common 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 common units may not be reportable by the unitholder and any cash distributions received by the unitholder as to those common units could be fully taxable as ordinary income. Our unitholders desiring to assure their status as partners and avoid the risk of gain recognition from a loan to a short seller are urged to consult a tax advisor to discuss whether it is advisable to modify any applicable brokerage account agreements to prohibit their brokers from loaning their common units.

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

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

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

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

We will be considered to have technically terminated 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. For purposes of determining whether the 50% threshold has been met, multiple sales of the same interest will be counted only once. Our technical termination would, among other things, result in the closing of our taxable year for all unitholders, which would result in us filing two tax returns (and our unitholders could receive two Schedules K-1 if relief was not available, as described below) 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. The IRS has recently announced a publicly traded partnership technical termination relief program whereby, if a publicly traded partnership that technically terminated requests publicly traded partnership technical termination relief and such relief is granted by the IRS, among other things, the partnership will only have to provide one Schedule K-1 to unitholders for the year notwithstanding two partnership tax years.

As a result of investing in our common units, you may become subject to state and local taxes and return filing requirements in jurisdictions where we operate or own or acquire properties.

In addition to federal income taxes, our 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 conduct business or control property now or in the future, even if they do not live in any of those jurisdictions. Our 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, our unitholders may be subject to penalties for failure to comply with those requirements. We conduct business in Indiana, Kentucky, Ohio, Pennsylvania and West Virginia. Each of these states currently 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.

ITEM 1B.		UNRESOLVED STAFF COMMENTS

None.

ITEM 2.		PROPERTIES

Mining Operations

See “Item 1. Business — Mining Operations” for specific information about our mining operations.

Coal Reserves

The estimates of our proven and probable reserves associated with our surface mining operations in Northern Appalachia are derived from our internal estimates, which estimates were audited by John T. Boyd Company, an independent mining and geological consulting firm. The estimates of our proven and probable reserves associated with our surface mining operations in the Illinois Basin and our proven and probable underground coal reserves are derived from reserve reports prepared by John T. Boyd Company. These estimates are based on geologic data, economic data such as cost of production and projected sale prices and assumptions concerning permitability and advances in mining technology. Our coal reserves are reported as “recoverable coal reserves,” which is the portion of the coal 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. These estimates are periodically updated to reflect past coal production, new drilling information and other geologic or mining data. Acquisitions or dispositions of coal properties will also change these estimates. Changes in mining methods may increase or decrease the recovery basis for a coal seam, as will changes in preparation plant processes. We maintain reserve information in secure computerized databases, as well as in hard copy. The ability to update or modify the estimates of our coal reserves is restricted to our engineering group and the modifications are documented.

As of December 31, 2010, all of our proven and probable coal reserves were “assigned” reserves, which are coal reserves that can be mined without a significant capital expenditure for mine development.

As of December 31, 2010, we owned 19% of our coal reserves and leased 81% of our coal reserves from various third-party landowners. The majority of our leases have terms denominated in years and we believe that the term of years will allow the recoverable coal reserves to be fully extracted in accordance with our projected mining plan. Some of our leases have an initial term denominated in years but also provide for the term of the lease to continue until exhaustion of the “mineable and merchantable” coal in the lease area so long as we comply with the terms of the lease.

It generally takes us from 12 to 30 months to obtain a SMCRA permit. Permits are issued for an initial five year term and must be renewed if mining is to continue after the end of the term. We submit and obtain new mining permits on a continuing basis to replace existing permits as they are depleted. Based on our current surface mining plan, we have proven and probable coal reserves with active permits that will allow us to mine for approximately the next three years. Given the current permitting environment, we intend to continually address the timing of our permitting process in such a way as to as much as possible avoid any material delays in obtaining or renewing permits on our remaining coal reserves associated with our mining operations.

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

		Total Tons of Proven and
		Probable Coal Reserves(1)
Mining Complex		Total				Owned				Leased
		(in million tons)
Surface Mining Operations:
Northern Appalachia (principally Ohio)
Cadiz			10.9				6.5				4.4
Tuscarawas County			7.6				0.1				7.5
Plainfield			6.4				0.8				5.6
Belmont County			6.2				1.6				4.6
New Lexington			5.7				3.7				2.0
Harrison(2)			5.1				5.1				—
Noble County			2.7				—				2.7
Total Northern Appalachia			44.6				17.8				26.8
Illinois Basin (Kentucky)
Muhlenberg County			23.5				—				23.5
Total Illinois Basin			23.5				—				23.5
Total Surface Mining Operations			68.1				17.8				50.3
Underground Coal Reserves:
Tusky			25.4				—				25.4
Total Underground Coal Reserves			25.4				—				25.4
Total			93.5				17.8				75.7
Percentage of Total			100.0	%			19.0	%			81.0	%

The following table provides information on particular characteristics of our coal reserves as of December 31, 2010:

		As Received Basis(1)
														# of				Proven and Probable Coal Reserves
														SO2/mm				Sulfur Content(1)
Mining Complex		% Ash				% Sulfur				Btu/lb.				Btu				Total				<2%				2-4%				>4%
																		(tons in millions)
Surface Mining Operations:
Northern Appalachia (principally Ohio)
Cadiz			11.9				3.4				11,500				6.0				10.9				0.9				5.0				5.0
Tuscarawas County			10.6				3.9				11,670				6.6				7.6				1.2				2.9				3.5
Plainfield			10.5				4.4				11,460				7.7				6.4				—				0.8				5.6
Belmont County			12.9				3.8				11,620				6.6				6.2				—				3.7				2.5
New Lexington			11.6				3.9				11,550				6.8				5.7				—				2.9				2.8
Harrison(2)			12.1				1.8				12,000				3.1				5.1				3.6				1.5				—
Noble County			12.1				4.7				11,200				8.3				2.7				—				0.4				2.3
Illinois Basin (Kentucky)
Muhlenberg County			10.9				3.6				11,309				6.4				23.5				—				22.8				0.7
Underground Coal Reserves:
Tusky			5.4				2.1				12,910				3.3				25.4				3.8				21.6				—

Office Facilities

We lease and own office space in Columbus, Ohio and Coshocton, Ohio, respectively, that is used by our general partner’s executive and administrative employees. Our Columbus, Ohio office space lease expires in 2015.

ITEM 3.		LEGAL PROCEEDINGS

Although we are, from time to time, 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 could 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 such 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.

ITEM 4.		RESERVED

PART II

ITEM 5.		MARKET FOR REGISTRANT’S COMMON EQUITY, RELATED UNITHOLDER MATTERS AND ISSUER PURCHASES OF EQUITY SECURITIES

Our common units are listed on the NYSE under the symbol “OXF” and began trading on July 14, 2010 on a “when-issued” basis. Prior to July 14, 2010, our common units were not listed on any exchange or traded in any public market. On March 14, 2011, the closing market price for the common units was $25.90 per unit. As of March 14, 2011, there were 10,341,416 common units outstanding. There were approximately 49 record holders of common units on December 31, 2010. This number does not include unitholders whose units are held in trust by other entities. The actual number of unitholders is greater than the number of holders of record.

The following table sets forth, for each period indicated, the high and low sales prices per common unit, as reported on the NYSE, and the cash distributions declared and paid per common unit for each quarter since our initial public offering:

		High				Low
Period		Price				Price				Distributions Declared Per Unit
Quarter ended September 30, 2010		$	19.80			$	16.44			$	0.3519
Quarter ended December 31, 2010		$	24.93			$	19.36			$	0.4375

We have also issued 10,280,380 subordinated units and 420,853 general partner units, for which there is no established public trading market. All of the subordinated units and general partner units are held by affiliates of our general partner. The affiliates of our general partner receive quarterly distributions on the subordinated units only after sufficient distributions have been paid to the common units.

Cash Distribution Policy

Our partnership agreement 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 cash reserves established by our general partner to provide for the conduct of our business, to comply with applicable law, any of our debt instruments or other agreements or to provide for future distributions to our unitholders for any one or more of the next four quarters. Our available cash may also include, if our general partner so determines, all or any portion of the cash on hand on the date of determination of available cash for the quarter resulting from working capital borrowings made subsequent to the end of such quarter. Working capital borrowings are generally borrowings that are made under a credit facility, commercial paper facility or similar financing arrangement that are used solely to pay distributions to unitholders.

Our partnership agreement provides that, during a period of time referred to as the “subordination period,” the common units will have the right to receive distributions of available cash from operating surplus each quarter in an amount equal to $0.4375 per common unit, which amount is defined in our partnership agreement as the minimum quarterly distribution, 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. Furthermore, no arrearages will be paid on the subordinated units. The practical effect of the subordinated units is to increase the likelihood that during the subordination period there will be available cash to be distributed on the common units.

The subordination period will end on the first business day after we have earned and paid from operating surplus generated in the applicable period at least (i) $1.75 (the minimum quarterly distribution on an annualized basis) on each outstanding common and subordinated unit and the corresponding distribution on our general partner units for each of three consecutive, non-overlapping four quarter periods ending on or after September 30, 2013 or (ii) $0.65625 per quarter (150.0% of the minimum quarterly distribution, which is $2.625 on an annualized basis) on each outstanding common and subordinated unit and the corresponding distributions on our general partner units for any four quarter period ending on or after September 30, 2011, in each case provided there are no arrearages on our common units at that time. In addition, the subordination period will end upon the removal of our general partner other than for cause if the units held by our general partner and its affiliates are not voted in favor of such removal. When the subordination period ends, each outstanding subordinated unit will convert into one common unit and any existing arrearages in payment of the minimum quarterly distribution on the common units will be extinguished. All of our subordinated units are held by AIM Oxford and C&T Coal.

Our general partner is entitled to 2.0% of all quarterly distributions that we make prior to our liquidation. This general partner interest is represented by 420,853 general partner units. Our general partner also currently holds incentive distribution rights that entitle it to receive increasing percentages, up to a maximum of 50.0%, of the cash we distribute from operating surplus in excess of $0.5031 per unit per quarter. The maximum distribution of 50.0% includes distributions paid to our general partner on its 2.0% general partner interest and assumes that our general partner maintains its general partner interest at 2.0%. The maximum distribution of 50.0% does not include any distributions that our general partner may receive on common units or subordinated units that it owns. We did not pay our general partner any amounts with respect to its incentive distribution rights in connection with distributions for 2010.

There is no guarantee that we will distribute quarterly cash distributions to our unitholders. Our cash distribution policy is subject to restrictions on cash distributions under our credit facility. Specifically, our credit facility contains financial tests and covenants that we must satisfy before quarterly cash distributions can be paid. In addition, our ability to pay quarterly cash distributions will be restricted if an event of default has occurred under our credit facility. See “Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operation — Liquidity and Capital Resources — Credit Facility.”

Our ability to pay quarterly cash distributions is also potentially restricted by the operating agreement of Harrison Resources, our joint venture with CONSOL Energy. Pursuant to the operating agreement, all members of Harrison Resources must approve cash distributions, other than tax distributions, to its members. The members of Harrison Resources have consistently approved cash distributions from Harrison Resources on a quarterly basis, including an aggregate of $5.9 million in distributions to us during 2010. In the future, however, there can be no assurance that we will receive regular cash distributions from Harrison Resources.

Unregistered Sales of Equity Securities

From our formation in August 2007 until July 19, 2010, we issued 91,996 Class A common units to our employees upon the vesting of phantom units granted under our long-term incentive plan. These unit amounts do not reflect the unit split that was effected in connection with our initial public offering. These transactions were exempt from registration under Section 4(2) of the Securities Act of 1933 or Rule 701 pursuant to compensatory benefit plans and contracts related to compensation.

Our general partner has the right to contribute a proportionate amount of capital to us to maintain its 2.0% interest if we issue additional units. Pursuant to the exercise of this right, on March 22 and 31, 2010, we received contributions of approximately $22,346 and $2,379, respectively, from our general partner as consideration for the issuance to our general partner of approximately 1,282 and 137 general partner units, respectively. These unit amounts do not reflect the unit split that was effected in connection with our initial public offering. These transactions were exempt from registration under Section 4(2) of the Securities Act of 1933.

On July 19, 2010, in connection with the closing of our initial public offering, our general partner contributed 175,000 of our common units to us in exchange for 175,000 general partner units in order to maintain its 2.0% general partnership interest in us. This transaction was exempt from registration pursuant to Section 4(2) of the Securities Act of 1933, as amended.

On October 29, 2010, December 31, 2010 and January 31, 2011, we received contributions of approximately $2,043, $20,194 and $5,349, respectively, from our general partner as consideration for the issuance to our general partner of approximately 106, 920 and 220 general partner units, respectively. These transactions were exempt from registration pursuant to Section 4(2) of the Securities Act of 1933, as amended. Issuer Purchases of Equity Securities

No purchases of our common units were made by us or on our behalf during 2010.

Securities Authorized for Issuance Under Equity Compensation Plan

Please read the information in this Annual Report on Form 10-K under “Item 12. Security Ownership of Certain Beneficial Owners and Management and Related Unitholder Matters,” which is incorporated by reference into this Item 5.

ITEM 6.		SELECTED FINANCIAL AND OPERATING DATA

The following table presents our selected financial and operating data, as well as that of our accounting predecessor and wholly owned subsidiary, Oxford Mining Company, as of the dates and for the periods indicated. The following table should be read in conjunction with “Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations.”

SELECTED FINANCIAL AND OPERATING DATA

		Oxford Resource Partners, LP																Oxford Mining Company
		(Successor)																(Predecessor)
														Period from
														August 24,				January 1,				Year
														2007 to				2007 to				Ended
		Years Ended December 31,												December 31,				August 23,				December 31,
		2010				2009				2008				2007				2007				2006
		(in thousands, except per ton amounts)
Statement of Operations Data:
Revenues:
Coal sales		$	311,567			$	254,171			$	193,699			$	61,324			$	96,799			$	141,440
Transportation revenue			38,490				32,490				31,839				10,204				18,083				27,771
Royalty and non-coal revenue			6,521				7,183				4,951				1,407				3,267				6,643
Total revenues			356,578				293,844				230,489				72,935				118,149				175,854
Costs and expenses:
Cost of coal sales (excluding DD&A, shown separately)			229,468				170,698				151,421				40,721				70,415				106,657
Cost of purchased coal			22,024				19,487				12,925				9,468				17,494				22,159
Cost of transportation			38,490				32,490				31,839				10,204				18,083				27,771
Depreciation, depletion and amortization			42,329				25,902				16,660				4,926				9,025				12,396
Selling, general and administrative expenses			14,757				13,242				9,577				2,114				3,643				2,097
Contract termination and amendment expenses, net			652				—				—				—				—				—
Total costs and expenses			347,720				261,819				222,422				67,433				118,660				171,080
Income (loss) from operations			8,858				32,025				8,067				5,502				(511	)			4,774
Interest income			12				35				62				55				26				30
Interest expense			(9,511	)			(6,484	)			(7,720	)			(3,498	)			(2,386	)			(3,672	)
Gain on purchase of business(1)			—				3,823				—				—				—				—
Net income (loss)			(641	)			29,399				409				2,059				(2,871	)			1,132
Less: Net income attributable to noncontrolling interest			(6,710	)			(5,895	)			(2,891	)			(537	)			(682	)			—
Net income (loss) attributable to Oxford Resource Partners, LP unitholders		$	(7,351	)		$	23,504			$	(2,482	)		$	1,522			$	(3,553	)		$	1,132
Net income (loss) allocated to general partner		$	(147	)		$	467			$	(50	)		$	30				n/a				n/a
Net income (loss) allocated to limited partner		$	(7,204	)		$	23,037			$	(2,432	)		$	1,492				n/a				n/a
Net income (loss) per limited partner unit:
Basic		$	(0.45	)		$	2.09			$	(0.24	)		$	0.17				n/a				n/a
Diluted		$	(0.45	)		$	2.08			$	(0.24	)		$	0.17				n/a				n/a
Weighted average number of limited partner units outstanding:
Basic			15,887,977				11,033,840				10,104,324				8,922,801				n/a				n/a
Diluted			15,887,977				11,083,170				10,104,324				8,926,360				n/a				n/a
Distributions paid per limited partner unit (2)		$	0.58			$	1.20			$	1.26			$	—				n/a				n/a

SELECTED FINANCIAL AND OPERATING DATA — (continued)

		Oxford Resource Partners, LP																Oxford Mining Company
		(Successor)																(Predecessor)
														Period from
														August 24,				January 1,				Year
														2007 to				2007 to				Ended
		Years Ended December 31,												December 31,				August 23,				December 31,
		2010				2009				2008				2007				2007				2006
		(in thousands, except per ton amounts)
Statement of Cash Flows Data:
Net cash provided by (used in):
Operating activities		$	37,997			$	38,637			$	33,992			$	(8,519	)		$	17,634			$	16,236
Investing activities			(82,623	)			(49,171	)			(23,942	)			(98,745	)			(16,619	)			(13,547	)
Financing activities			42,149				(1,279	)			4,494				106,724				(234	)			(2,548	)
Other Financial Data:
Adjusted EBITDA (3)		$	51,617			$	56,967			$	24,686				8,120				10,691				16,998
Distributable cash flow (4) (5)			8,526				n/a				n/a				n/a				n/a				n/a
Reserve replacement expenditures (6)			3,353				3,057				2,526				163				1,297				3,881
Other maintenance capital expenditures (6)			25,028				25,657				25,321				7,420				11,305				9,665
Balance Sheet Data (at period end):
Cash and cash equivalents		$	889			$	3,366			$	15,179			$	635			$	1,175			$	392
Trade accounts receivable			28,108				24,403				21,528				17,547				18,396				16,826
Inventory			12,640				8,801				5,134				4,655				4,824				3,977
Property, plant and equipment, net			198,694				149,461				112,446				106,408				54,510				48,001
Total assets			261,071				203,363				171,297				146,774				90,893				80,533
Total debt (current and long-term)			102,986				95,711				83,977				75,529				43,165				43,697
Operating Data:
Tons of coal produced (clean)			7,470				5,846				5,089				1,634				2,693				3,913
Tons of coal purchased			734				530				434				305				641				962
Tons of coal sold			8,151				6,311				5,528				1,938				3,333				4,872
Tons sold under long-term contracts (7)			95.9	%			97.8	%			93.8	%			98.9	%			96.6	%			99.5	%
Average sales price per ton (8)		$	38.22			$	40.27			$	35.04			$	31.64			$	29.04			$	29.03
Cost of purchased coal sales per ton (9)		$	30.00			$	36.79			$	29.81			$	31.08			$	27.29			$	23.03
Cost of coal sales per ton produced (10)		$	30.94			$	29.52			$	29.81			$	24.93			$	26.16			$	27.27
Number of operating days — NAPP operations			275.5				274.5				280.0				97.5				181.5				277.0
Number of operating days — ILB operations			273.0				60.5				n/a				n/a				n/a				n/a