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 19 active surface mines one of which became an active mine in the first quarter of 2012, that are managed as eight mining complexes. Our operations also include two river terminals, strategically located in eastern Ohio and western Kentucky. During 2011, we produced 8.0 million tons of coal. During 2011, we sold 8.5 million tons of coal, including 0.4 million tons of purchased coal. As a result, our coal inventory on hand decreased by approximately 0.1 million tons. As is customary in the coal industry, we have entered into long-term coal sales contracts with most 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, 2011, we owned and/or controlled 88.0 million tons of proven and probable coal reserves, of which 63.3 million tons were associated with our surface mining operations and the remaining 24.7 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 2011, we acquired 5.9 million tons of proven and probable coal reserves, an amount approximately equal to 74% of our 2011 production.

The following table summarizes our mining complexes, our coal production for the year ended December 31, 2011 and our coal reserves as of December 31, 2011:

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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 39 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 acquired the active surface mining operations of Phoenix Coal Corporation (“Phoenix Coal”). 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 from 2011 through 2035 by 5.7%, 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.

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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 2011, coal-fired power plants produced approximately 44.0% of all electric power generation and steam coal accounted for 93% 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.

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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 19 active surface mines one of which became an active mine in 2012, 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 fourteen 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 both Northern Appalachia and the Illinois Basin, 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. These 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 five blending facilities:

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

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

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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, 2011, 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, 2011 and for the years indicated:

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 currently consists of the Daron, Bundy, Ellis 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, 2011, the Cadiz mining complex included 9.0 million tons of proven and probable coal reserves. The infrastructure at this mining complex includes two coal crushers, 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 the area, contour, auger and highwall miner methods of surface mining. This mining complex produced 1.7 million tons of coal for the year ended December 31, 2011.

Tuscarawas County Mining Complex.  The Tuscarawas County mining complex is located in Tuscarawas, Columbiana and Stark Counties, Ohio, and currently consists of the Stonecreek, Stillwater, Lisbon, Strasburg and East Canton 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, 2011, the Tuscarawas County mining complex included 6.4 million tons of proven and probable coal reserves. The infrastructure at this mining complex includes three coal crushers with truck scales, Stonecreek and Strasburg blending facilities and the Strasburg wash plant. Coal produced from the Tuscarawas County mining complex is transported by truck 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, 2011.

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Plainfield Mining Complex.  The Plainfield mining complex is located in Muskingum, Guernsey and Coshocton Counties, Ohio, and currently consists of the Otsego 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, 2011, the Plainfield mining complex included 5.4 million tons of proven and probable coal reserves. The infrastructure at this mining complex includes our Barb Tipple blending and coal crushing facility and truck scale. 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 0.2 million tons of coal for the year ended December 31, 2011.

Belmont County Mining Complex.  The Belmont County mining complex is located in Belmont County, Ohio, and currently consists of the Lafferty, 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, 2011, the Belmont County mining complex included 9.0 million tons of proven and probable coal reserves. Coal produced from this 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 1.0 million tons of coal for the year ended December 31, 2011.

New Lexington Mining Complex.  The New Lexington mining complex is located in Perry, Athens and Morgan Counties, Ohio, and currently 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, 2011, the New Lexington mining complex included 4.7 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, auger and highwall miner method of surface mining. This mining complex produced 0.8 million tons of coal for the year ended December 31, 2011.

Harrison Mining Complex.  The Harrison mining complex is located in Harrison County, Ohio, and currently 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% of Harrison Resources and CONSOL Energy owns the remaining 49% 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, 2011 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% 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, 2011, the Harrison mining complex included 4.3 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 0.8 million tons of coal for the year ended December 31, 2011.

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Noble County Mining Complex.  The Noble County mining complex is located in Noble and Guernsey Counties, Ohio, and currently consists of the Shuman mine. 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, 2011, the Noble County mining complex included 2.4 million tons of proven and probable coal reserves. Coal produced from this 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. The Noble County mining complex uses the area, contour and auger methods of surface mining. This mining complex produced 0.4 million tons of coal for the year ended December 31, 2011.

Muhlenberg County Mining Complex.  The Muhlenberg County mining complex is located in Muhlenberg and McClean Counties, in western Kentucky, and currently consists of the Schoate, Highway 431, 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, 2011, the Muhlenberg County mining complex included 22.1 million tons of proven and probable coal reserves. The infrastructure at this mining complex includes four coal crushers 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. This mining complex uses the area method of surface mining. This mining complex produced 2.2 million tons of steam coal during the year ended December 31, 2011.

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 13 years remaining on the lease for our underground coal reserves, and our sublessee has 13 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, 2011, we had

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approximately $38.5 million in surety bonds and $14,000 in cash bonds outstanding to secure the performance of our reclamation obligations. Additionally, as of December 31, 2011, our surety bonds were supported by approximately $7.5 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.

Approximately 79% 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 AMD Inventory List. 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 $224,000 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. Three 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.

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. During 2011 we produced and sold 0.9 million tons of limestone, and our revenues for the year ended December 31, 2011 included $3.5 million in limestone sales.

Based on estimates from our internal engineers, our Cadiz mining complex has 6.4 million tons of proven and probable limestone reserves as of December 31, 2011. 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 2011, we generated $2.6 million of revenue from a variety of services we performed in connection with our surface mining operations. This revenue included the following:

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.”

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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, 2011, we derived 77.6% of our revenues from coal sales to electric utilities (including sales through brokers), 12.2% from coal sales to municipalities and cooperatives, 7.6% from coal sales to industrial customers and the remaining 2.6% 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 five years over 90% 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 more 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.

For 2012, 2013, 2014 and 2015, we currently have long-term coal sales contracts for coal sales of 7.3 million tons, 6.5 million tons, 5.5 million tons and 4.0 million tons, respectively. These tonnages assume the successful renegotiation of some of our long-term coal sales contracts which contain provisions that provide for price reopeners. Two of our long-term coal sales contracts with the same customer provide for market-based adjustments to the initial contract price every three years. These two long-term coal sales contracts will terminate effective December 31, 2012 if we cannot agree upon a market-based price with the customer by September 30, 2012. In addition, we have one long-term coal sales contract with another customer that will terminate effective December 31, 2013 if we cannot agree upon a market-based price with the customer by June 30, 2013. The coal tonnage which is involved for these three contracts is 1.0 million tons for 2013, 1.4 million tons for 2014 and 0.9 million tons for 2015.

The terms of our coal sales contracts result from competitive bidding and negotiation 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 and/or cost adjustment provisions. For 2012, 2013, 2014 and 2015, 70%, 72%, 61% and 48% 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.

Some long-term coal sales contracts contain option provisions that give the customer the right to elect to purchase additional tons of coal during the contract term at the same price as the fixed tons provided for in the contract. We have outstanding option tons of 0.4 million for each of 2012 through 2014 and 0.7 million for 2015. If there are customer elections to receive these option tons, we believe we will have the operating flexibility to meet these requirements through increased production at our mining complexes.

We concluded our long-standing negotiations with American Electric Power Service Corporation (“AEP”) to amend our long-term coal sales contract with them in October of 2011. The mutual goal of the parties was achieved to amend the contract to extend the term of the agreement, establish a future pricing methodology acceptable to both parties, and adjust the amounts of fixed and optional coal tonnage covered by the contract. In this amendment, the pricing is tied to and adjusted periodically based on indices reflecting current market pricing, and pricing adjusters were eliminated. By reason of this amendment, the current term of the contract now runs through 2015, and it can be automatically extended for a further three-year term through 2018 if AEP gives us eighteen months advance notice of its election to extend the contract. Further, in more recent negotiations we have reached an agreement in principle to reduce the 2012 contract tonnage in exchange for a compensating increase in pricing, and we are working to formalize that arrangement in a contract amendment.

On March 2, 2012, we received a notice of contract termination from Big Rivers Electric Corporation (“Big Rivers”). The notice notified us that Big Rivers was terminating the Amended and Restated Coal Supply Agreement between Big Rivers and us (the “Big Rivers Agreement”) effective as of the close of business on March 2, 2012, pursuant to provisions of the Big Rivers Agreement permitting termination in certain circumstances where coal deliveries have not conformed to the quality specifications in the Big Rivers Agreement. The Big Rivers Agreement provides for us to supply to Big Rivers 800,000 tons of coal per year, and absent any termination thereof the term of the Big Rivers Agreement runs

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until December 31, 2015. We have met with representatives of Big Rivers on two occasions following this action (on March 7 and March 12, 2012), but have been unable to achieve any satisfactory resolution of the issues during these meetings. We are assessing the validity of the termination notice and any recourse that we may have under the Big Rivers Agreement or otherwise with respect to the actions by Big Rivers, including the termination. We are also assessing the financial and operational impact that such a termination would have on us and reviewing various alternatives, including without limitation mine closure(s) and related cost reduction measures, to compensate for and/or lessen any impact from such actions by Big Rivers and to bring our production and related cost structure in balance with our remaining contractual commitments.

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 and/or use coal deliveries.

Customer Concentration

We derived 92.3% of our total revenues from coal sales to our ten largest customers for the year ended December 31, 2011, with our top five customers accounting for 77.8% of our total revenues. For the year ended December 31, 2011, we derived 34.9%, 14.5%, 11.0%, 10.9% and 6.5% of our revenues from AEP, First Energy, Big Rivers Electric, East Kentucky Power Cooperative and Duke Energy, respectively.

Transportation

Our coal is delivered to our customers by barge, truck or rail. Approximately 57% of the coal we shipped during 2011 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, 2012. 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). For the year ended December 31, 2011, 57%, 42% and 1% of our coal sales tonnage was shipped by barge, truck and rail, respectively.

We believe that we have good relationships with our rail carrier and trucking 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, 2011, expenses we incurred to obtain goods and services in support of our mining operations were approximately $154.1 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, 2011, 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.

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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 continually strive to operate our mines with a focus on safety. Over the last 5 years, our Mine Safety and Health Administration, or MSHA, reportable incident rate was, on average, 2.0 which is equal to the national surface mine average. 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, increased public participation 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 may have 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 become subject to legal challenge by environmentalists and other advocacy groups.

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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 has primacy to administer the SMCRA program in its territory.

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 these 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, as well as compliance information from OSM’s Applicant Violator System, or AVS, which includes 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 timeframe for permitting is a function of the discretion vested in the various regulatory authorities, including with respect to the handling of comments and objections relating to the project received from affected communities, other governmental agencies 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

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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 ruled that OSM could not withdraw the revised SBZ Rule 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, or EIS, for a new rule – to be called the Stream Protection Rule – that will evaluate alternatives for revising surface mining rules to better protect streams. OSM received public comments during the summer of 2010 and is developing a draft EIS. On February 13, 2012, OSM stated that it expects to release the draft EIS in April 2012. 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 2011, we recorded $2.4 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, 2011, we had approximately $38.5 million in surety bonds outstanding to secure the performance of our reclamation obligations, which were supported by approximately $7.5 million in letters of credit.

Mine Health and Safety

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 (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

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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 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 21, 2011, the SEC issued final rules implementing Section 1503, outlining the way in which mining companies must disclose to investors certain information about mine safety and health standards. These new SEC rules were adopted as final in December 2011, and became effective on January 27, 2012. They require disclosure of the total numbers of health or safety-related violations, citations, orders, notices, assessments, fatalities and legal actions on a mine-by-mine basis. Our disclosure in this regard can be found in “Exhibit 95, Mine Safety Disclosure.”

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 2011, we recorded $4.2 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 the results of our 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, including 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.

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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:

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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.

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 authorization by its December 2009 endangerment finding made in response to the 2007 U.S. Supreme Court’s ruling in Massachusetts v. EPA. 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 increased 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 further modified 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

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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.

On June 20, 2011, the U.S. Supreme Court ruled in American Electric Power Co., Inc. v. Connecticut that the Clean Air Act and U.S. EPA regulation of carbon dioxide emissions thereunder preempt any federal common law right for abatement of a public nuisance based upon global warming allegedly caused by out-of-state emissions from fossil-fuel fired power plants.

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 rulings 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 wastewater or 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. Such changes 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:

The CWA and corresponding state laws also protect waters that states have been designated for special protections including those designated as: impaired (i.e., as not meeting present water quality standards) through total maximum daily load (TMDL) restrictions; and “high quality/exceptional use” stream designations that restrict discharges that could result in their degradation. Other requirements necessitate the treatment of discharges from coal mining properties for non-traditional pollutants, such as chlorides, selenium and dissolved solids, and avoidance of impacts to streams, wetlands, other regulated water resources and associated riparian lands from surface and 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.

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Since 2003, environmental groups have pursued litigation particularly 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. One 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 based upon deference to the expertise of the Corps in review of the permit applications. On August 19, 2010, the U.S. Supreme Court dismissed the petition for writ of certiorari in the case.

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, 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 based on what the EPA contended was “new” information on the impacts of valley fills on downstream water quality. These EPA comments 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, EPA and the U.S. Department of the Interior announced an interagency action plan for “Enhanced Coordination” 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 and EPA committed to undertake an “Enhanced Coordination Process” in reviewing Section 404 permit applications for such projects. Moreover, on April 1, 2010, the EPA issued interim final guidance substantially revising the environmental review of CWA permits by state and federal agencies.

In 2010, the National Mining Association, or NMA, the State of West Virginia, and the Kentucky Coal Association and other plaintiffs challenged these EPA guidance’s in ( National Mining Association v. Jackson, et al, (D.D.C.) . On October 6, 2011, the District Court ruled that the EPA had exceeded its statutory authority, and that the challenged EPA guidance documents were legislative rules that were adopted in violation of notice and comment requirements.

On June 18, 2010, the Corps announced the suspension of the NWP 21 in the Appalachian regions of Kentucky, Ohio, Pennsylvania, Tennessee, Virginia and West Virginia 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.

On February 16, 2011, the Corps solicited comments on three options for the possible reissuance of NWP 21: Option 1 would be to not reissue NWP 21; Option 2 would be to reissue NWP 21 with modifications, including a  ¹ / 2 -acre limit for losses of non-tidal waters, a 300-foot limit for the loss of stream bed (with possible waiver for the loss of intermittent and ephemeral stream beds under certain conditions) and a prohibition on its use for valley fills; and Option 3 would be the same as Option 2 without the prohibition on valley fills. The Corps’ preferred option is Option 2. Although the comment period has ended, the Corps’ final action on reissuance of NWP 21 is still pending.

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Despite the ruling in National Mining Association v. Jackson , on July 21, 2011, EPA issued its final guidance on Improving EPA Review of Appalachian Surface Coal Mining Operations Under the Clean Water Act, National Environmental Policy Act, and the Environmental Justice Executive Order. This final guidance replaces EPA’s interim guidance released on April 1, 2010. The final guidance calls for the imposition of additional discharge restrictions under Section 402 of the CWA, including water-quality based effluent limits, Whole Effluent Toxicity (WET) limits and other permit conditions. It also calls for greater scrutiny of Section 404 applications for less damaging practicable alternatives, protection against water quality standards violations, prevention of significant deterioration of water quality, minimization of water quality impacts and adequate mitigation of project impacts. The new requirements and procedures imposed by EPA’s final guidance are expected to make permitting for Appalachian surface coal mining activities more difficult, and increase the regulatory burdens imposed on such projects. These initiatives likely will extend the time required to obtain permits for coal mining and that the costs associated with obtaining and complying with those permits will increase substantially. Additionally, any future changes could further restrict our ability to obtain other new permits or to maintain existing permits.

Resource Conservation and Recovery Act

The Resource Conservation and Recovery Act, or RCRA, regulates the management of solid and hazardous wastes from the point of generation through treatment and disposal. RCRA hazardous waste requirements do not apply to most of the wastes generated at coal mines, overburden and coal cleaning wastes, because such materials are not considered hazardous wastes under RCRA regulations. 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, coal combustion residuals (CCRs), often referred to as coal ash, are currently considered exempt wastes under an amendment to RCRA known as the Bevill Exclusion. Most state solid waste laws also regulate coal combustion residuals as non-hazardous wastes. The EPA is currently considering what type of RCRA regulation is warranted for certain CCR’s when used as mine-fill. In June 2010, EPA published a proposal to regulate CCR as either a non-hazardous waste under Subtitle D of RCRA by issuing national minimum criteria or as special wastes under Subtitle C of RCRA when they are destined for disposal in landfills or surface impoundments. On October 21, 2010, EPA published a Notice of Data Availability (NODA) on CCR surface impoundments, and on October 12, 2011, EPA issued another NODA inviting comment on additional information obtained by EPA in conjunction with the June 21, 2010 proposed rule. However, EPA has yet to take final action on the proposed rule. If CCR is regulated under RCRA, 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.

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 transporters 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 or chemicals used by coal companies in operations 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. 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

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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 Substances Control Act and the Emergency Planning and Community Right-to-Know Act.

Employees

To carry out our operations, our general partner employed 929 full-time employees as of December 31, 2011. 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, as amended, 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.

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