Item 1.             BUSINESS

Overview

We are a low-cost producer and marketer of high-value thermal coal (coal) to United States (“U.S.”) utilities and industrial users, and we are the largest producer of surface mined coal in Ohio. We market our coal primarily to large electric utilities with coal-fired, base-load scrubbed power plants under long-term coal sales contracts. We focus on acquiring thermal coal reserves that we can efficiently mine with our large-scale equipment. Our reserves and operations are strategically located to serve our primary market area of Indiana, Kentucky, Michigan, Ohio, Pennsylvania and West Virginia.

We operate in a single business segment and have three operating subsidiaries, Oxford Mining Company, LLC ("Oxford Mining"), Oxford Mining Company-Kentucky, LLC and Harrison Resources. All of our operating subsidiaries participate primarily in the business of utilizing surface mining techniques to mine domestic coal and prepare it for sale to our customers. All three subsidiaries share common customers, assets and employees.

As of December 31, 2013, management estimates that we owned or controlled approximately 81.6 million tons of coal reserves, of which we have subleased 24.3 million tons of underground reserves to a third party. The estimates are based on an initial evaluation, as well as subsequent acquisitions, dispositions, depleted reserves, changes in available geological or mining data and other factors.

For the year ended December 31, 2013, we sold 6.6 million tons of coal, compared to 7.3 million tons for the year ended December 31, 2012, of which approximately 6.1 million and 6.8 million tons, respectively, were produced from our mining activities and approximately 0.5 million tons, were purchased through brokered coal contracts (coal purchased from third parties for resale), at an average sale price of $49.04 and $44.42, respectively, for the years ended December 31, 2013 and 2012. For the year ended December 31, 2013, we derived approximately 93.9% of our total coal revenues from sales to our ten largest customers, with the following top three customers and their affiliates accounting for approximately 74.1% of our coal revenues for that period: American Electric Power Company, Inc. ( 42.2%); FirstEnergy Corp. ( 20.0%); and East Kentucky Power Cooperative ( 12.0%).

As previously disclosed in our periodic filings with the SEC, in the first quarter of 2012 we received a termination notice from a customer related to a 0.8 million tons per year coal supply contract fulfilled from our Illinois Basin operations. In response, we idled an Illinois Basin mine and the related preparation plant and lab, reduced operations at two other mines, terminated a significant number of employees and substituted purchased coal for mined and washed coal on certain sales contracts.

As of December 31, 2013, all Illinois Basin operations have been idled, with the redeployment of the remaining Illinois Basin equipment to our Northern Appalachian operations expected to culminate during the first quarter of 2014. We expect these remaining restructuring efforts to cost an additional $ 0.1 million. Additionally, we are seeking to sell the remaining Illinois Basin equipment, consisting of a large-capacity shovel and several smaller pieces of equipment, and would consider offers for the remaining coal reserves and/or facilities related to the Illinois Basin operations.

Oxford Resource Partners, LP is a Delaware limited partnership listed on the New York Stock Exchange (“NYSE”) under the ticker symbol “OXF.” OXF was formed by American Infrastructure MLP Fund, L.P. (“AIM”) and C&T Coal, Inc. (“C&T Coal”) in August 2007. On July 19, 2010, we closed our initial public offering of common units. 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 (“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 through June 30, 2013. In connection with our formation, our founders contributed all of their interests in Oxford Mining 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 in 1985 to provide contract-mining services to a mining division of a major oil company. In 1989, our founders transitioned Oxford Mining from a contract miner into a producer of its own coal reserves. In January 2007, Oxford Mining entered into a joint venture, Harrison Resources, with a subsidiary of CONSOL to mine surface coal reserves purchased from CONSOL. 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.

The Coal Industry

The coal industry is a major contributor to the world energy supply. Coal provides approximately 30% of the global primary energy needs and generates 41% of the world’s electricity according to the World Coal Association. According to the Energy Information Administration (“EIA”), a statistical agency of the U.S. Department of Energy, coal-fired plants generated approximately 39.1% of the electricity produced in the United States in 2013. The EIA forecasts the coal share of total electric power generation in the United States to rise from 39.1% in 2013 to 40.2% in 2014, with thermal coal remaining the dominant fuel source in the future.

Short-Term Outlook

Coal Markets

Coal produced in the United States is used primarily by utilities to generate electricity, by the steel industry to produce coke for use in blast furnaces, and by a variety of industrial users to heat and power foundries, cement plants, paper mills, chemical plants and other manufacturing and processing facilities. Significant quantities of coal are also exported from both East and West Coast terminals.

Thermal coal has long been favored by utilities as an electricity generating fuel because of its basic economic advantage. The largest cost component in electricity generation is fuel and, historically, coal has been considerably less expensive than natural gas or oil. However, the growth of hydraulic fracturing (fracking) resulted in record high supplies and inventories of natural gas altering the competitive balance; allowing natural gas to gain market share in the power generation market. According to the EIA, coal production decreased by almost 9% between 2011 and 2013, but is expected to increase by 3.6% in 2014 as higher natural gas prices are expected to result in increased coal requirements at coal-fired power plants as the drawdown of coal inventory ends. In 2015, however, the EIA forecasts that coal-fired electricity generation will fall by 2.5% as retirements of coal-fired power plants rise due to the implementation of the U.S. Environmental Protection Agency's Mercury and Air Toxics Standards.

The other major market for coal is the steel industry. The type of coal used in steel making, referred to as “metallurgical coal,” is distinguished by special quality characteristics that include high-carbon content, favorable coking characteristics and various other chemical attributes. Metallurgical coal is generally higher in heat content (as measured in Btu), and therefore is also desirable to utilities as fuel for electricity generation. However, the premium price offered by steel makers for the metallurgical quality attributes is typically higher than the price offered by utility coal buyers that value only the heat content.

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 affect the demand for coal. A series of more stringent requirements has been proposed or enacted by federal and 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.

Additionally, coal competes with other fuels, such as natural gas, nuclear energy, hydropower, wind, solar and petroleum, for steam and electrical power generation. Costs and other factors relating to these alternative fuels, such as safety and environmental considerations, affect the overall demand for coal as a fuel.

Coal Mining Methods

Coal is mined using two primary methods, surface mining and underground mining. For the year ended December 31, 2013, we exclusively produced coal using the surface mining method, which is explained as follows:

Surface Mining

Surface mining is used when coal is found close to the surface. This method involves the removal of topsoil and overburden (earth and rock covering the coal) with heavy equipment and explosives, extraction of the coal, replacing the overburden and topsoil to restore the land after the coal has been removed, reestablishing vegetation and frequently other improvements that have local community and environmental benefit.

Topsoil and overburden is typically removed using large dozers and rubber-tired diesel loaders or hydraulic shovels. Coal is loaded into haul trucks for transportation to a preparation plant or unit train loading facility or directly to a barge loading facility. Seam recovery for surface mining is typically between 80% and 90%. Productivity depends on equipment, geological composition and mining ratios.

Area mining. Area mining is a surface mining method that removes all or part of the coal seam(s) in the upper fraction of a mountain, ridge or hill and the disturbed areas are subsequently restored to approximate original contour, or an approved alternate configuration.

Cross-ridge mining. Cross-ridge mining is a form of area mining that is employed where the terrain is dominated by long narrow ridges.

Contour mining . Contour mining is a surface mining method used in hilly terrain that recovers coal along the outcrop of a coal seam by progressively excavating the overburden from above the coal seam to create a narrow bench, removing the coal and then replacing the overburden to restore the approximate original contour of the mined area.

Mountaintop removal mining . Mountaintop removal mining is a surface mining method that removes the entire coal seam(s) in an upper fraction of a mountain, ridge or hill and creates a level plateau or a gently rolling contour with no highwalls. This mining method is limited in application to sites where the approved post-mining land use requires relatively flat terrain. We do not currently have any mountaintop removal operations.

Auger mining: Auger mining is usually associated with contour surface mining. With this method, the coal is removed by drilling auger holes from the last contour cut and extracting it in the same manner that shavings are produced by a carpenter’s bit. Coal recovery rates approach 40% with this method.

Highwall mining. Highwall mining is a surface mining method generally utilized in conjunction with contour surface mining. At a highwall mining operation, a modified continuous miner, with an attached coal conveying system, cuts horizontal passages from the face of a highwall into a coal seam. These passages can penetrate to a depth of up to 1,100 feet. This method can recover up to 65% of the reserve block penetrated.

Coal Preparation and Blending

Depending on coal quality and customer requirements, some raw coal may be shipped directly from the mine to the customer. However, the quality of some raw coal does not allow direct shipment to the customer without putting the coal through a preparation plant, a process that physically separates impurities from coal. This processing upgrades the quality and heating value of the coal by removing or reducing sulfur and ash-producing materials, but it entails additional expense and results in some loss of coal. Coals of various sulfur and ash contents can be mixed, or “blended,” at a preparation plant or loading facility to meet the specific combustion and environmental needs of customers. Coal blending helps increase profitability by meeting the quality requirements of specific customer contracts, while maximizing revenue through optimal use of coal inventories.

Coal Characteristics

In general, coal of all geological composition is characterized by its end use as either thermal coal or metallurgical coal. Heat value and sulfur content are the most important variables in assessing the marketability and profitability of thermal coal, while ash, sulfur and various coking characteristics are the most important variables assessing marketability and profitability of metallurgical coal. We mine, process, market and transport bituminous thermal coal. Thermal coal also includes sub-bituminous coal and lignite. We have some competition from producers of sub-bituminous coal, but do not compete with producers of lignite or metallurgical coal.

Bituminous Coal

Bituminous coal typically has a heat content that ranges from 9,500 to 14,000 Btus per pound. This coal, located primarily in Appalachia, Arizona, Colorado, the Midwest and Utah, is the type most commonly used by utilities for electricity generation in the United States. Industrial customers also use bituminous coal for generating steam.

Heat Value

The heat value of coal is commonly measured in Btus per pound of coal. A Btu is the amount of heat needed to raise one pound of water one degree Fahrenheit. Coal found in the eastern and Midwestern regions of the U.S. tends to have a heat content ranging from 10,000 to 14,000 Btus per pound. Most coal found in the western U.S. ranges from 8,000 to 10,000 Btus per pound.

Sulfur Content

Sulfur content can vary from coal seam to coal seam, and sometimes within a seam. When coal is burned, it produces sulfur dioxide, the amount of which varies depending on the chemical composition and the concentration of sulfur in the coal. Compliance coal is coal which, when burned, emits 1.2 pounds or less of sulfur dioxide per million Btus and complies with the requirements of the Clean Air Act Acid Rain Program. Low-sulfur coal, when burned, emits approximately 1.6 pounds or less of sulfur dioxide per million Btus. Mid-sulfur coal, when burned, emits greater than 1.6 pounds of sulfur dioxide per million Btus, but less than 2.5 pounds of sulfur dioxide per million Btus. High-sulfur coal, when burned, emits greater than 2.5 pounds per million Btus.

High-sulfur coal can be burned in electric utility plants equipped with sulfur-reduction technology, such as scrubbers, which can reduce sulfur dioxide emissions by up to 99%. Plants without scrubbers can burn high-sulfur coal by blending it with lower-sulfur coal or by purchasing emission allowances on the open market. Each emission allowance permits the user to emit a ton of sulfur dioxide. Additional scrubbing will provide new market opportunities for our medium- to high- sulfur coal. Any new coal-fired electric utility generation plants built in the U.S. will use some form of clean coal-burning technology.

Other Characteristics

Ash is the inorganic residue remaining after the combustion of coal. As with sulfur content, ash content varies from coal seam to coal seam. Ash content is an important characteristic of coal because it adds weight, but not heat value, and therefore increases transportation costs. Additionally, electric generating plants must handle and dispose of ash following combustion.

Moisture content of coal varies by the type of coal, the region where it is mined and the location of coal within a seam. In general, high-moisture content decreases the heat value per pound of coal, thereby increasing the delivered cost per Btu. The moisture content can range from approximately 5% to 30% of the coal’s weight.

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 are used to move coal over shorter distances.

Although the purchaser typically bears the freight costs, transportation costs are still an important consideration because the purchaser may choose a supplier largely based on the total delivered cost of coal, which includes the cost of transportation. It is not uncommon for two or more modes to be used to ship coal (i.e., intermodal movements). The method of transportation and the delivery distance can greatly impact the total cost of coal delivered to the customer.

Typically, we pay the transportation costs for our coal to be delivered to the barge or rail loadout facility, where it is then loaded for final delivery. Transportation costs can vary greatly based on the mine’s proximity to the loadout facilities. Customers typically pay for the transportation cost from the loading facility to its final destination. We use a variety of independent companies for our transportation needs and enter into multiple agreements with transportation companies throughout the year.

In 2013, approximately 64.7% of our coal sales were delivered to our customers by barge, with the remaining 35.0% and 0.3% delivered by truck and other methods, respectively. We believe we have good relationships with rail, barge and trucking companies due, in part, to our modern coal-loading facilities and the experience of our transportation and distribution employees.

Operations

As of December 31, 2013, we operated 16 active surface mines and managed these mines as six mining complexes located in eastern Ohio. These mining facilities include two preparation plants, each of which receive, wash, blend, process and ship coal produced from one or more of our 16 active mines. Our mines are a combination of area, contour, auger and highwall mining methods using truck/shovel and truck/loader equipment along with large production dozers. We also own and operate seven augers moving them among our mining complexes, as necessary, and two highwall miner systems. Additionally, we have contracted with a third party to operate an additional highwall miner system, owned by the third party.

Currently, we own or lease most of the equipment utilized in our mining operations and employ preventive maintenance and rebuild programs to ensure that our equipment is well maintained. The mobile equipment utilized at our mining operations is replaced on an on-going basis with new, more efficient units based on equipment age and mechanical condition. We endeavor to replace the oldest units, thereby maintaining productivity, while minimizing capital expenditures.

For the years ended December 31, 2013 and 2012, we produced 6.1 and 6.8 million tons of coal, respectively, and sold 6.6 and 7.3 million tons of coal, respectively, including 0.5 million tons of purchased coal, respectively.

As of December 31, 2013, we owned and/or controlled 81.6 million tons of proven and probable coal reserves, of which 57.3 million tons were associated with our surface mining operations and the remaining 24.3 million tons consisted of underground coal reserves that we have subleased to a third party in exchange for a royalty. Historically, we have been successful at acquiring reserves with low operational, geologic and regulatory risks, located near our existing mining operations or that otherwise had the potential to serve our primary market area. In 2013, we obtained control of 6.2 million tons of proven and probable coal reserves, an amount greater than our 2013 production.

The following table summarizes our mining complexes, our coal production for the year ended December 31, 2013 and our coal reserves as of December 31, 2013:

Northern Appalachia

The following map shows the locations of our Northern Appalachia mining operations and coal reserves and related transportation infrastructure as of December 31, 2013:

We operate seven surface mining complexes in Northern Appalachia, substantially all of which are located in eastern Ohio. For the year ended December 31, 2013, our mining complexes in Northern Appalachia produced an aggregate of 5.8 million tons of thermal coal. The following table provides summary information regarding our mining complexes in Northern Appalachia for the years indicated:

Cadiz Mining Complex

The Cadiz mining complex, located principally in Harrison County, Ohio, also includes reserves located in Jefferson County, Ohio, and currently consists of the Daron, Ellis, Pasco, and Sandy Ridge mines. We began 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, 2013, the Cadiz mining complex included 6.9 million tons of proven and probable coal reserves. 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, or trucked to our Strasburg preparation plant 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. The infrastructure at this mining complex includes two coal crushers, two truck scales and the Cadiz rail loadout. This mining complex produced 1.9 million tons of coal for the year ended December 31, 2013.

Tuscarawas Mining Complex

The Tuscarawas mining complex is located in Tuscarawas, Columbiana and Stark Counties, Ohio, and currently consists of the East Canton, Hunt, Strasburg, Stillwater and Stone Creek mines. We began 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, 2013, the Tuscarawas mining complex included 7.4 million tons of proven and probable coal reserves. Coal produced from the Tuscarawas mining complex is transported by truck directly to our customers, our Barb Tipple blending and coal crushing facility or our Strasburg preparation plant. Coal trucked to our Barb Tipple blending and coal crushing facility or our Strasburg preparation plant is then transported by truck to the customer after processing is completed. This mining complex uses the area, contour, and auger methods of surface mining. The infrastructure at this mining complex includes three coal crushers with truck scales, the Stone Creek and Strasburg blending facilities and the Strasburg preparation plant. This mining complex produced 1.2 million tons of coal for the year ended December 31, 2013.

Plainfield Mining Complex

The Plainfield mining complex is located in Muskingum, Guernsey and Coshocton Counties, Ohio, and is currently inactive. We began 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, 2013, the Plainfield mining complex included 2.8 million tons of proven and probable coal reserves. 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 Conesville preparation plant and then transported by truck to the customer. This mining complex uses contour and highwall miner methods of surface mining. The infrastructure at this mining complex includes our Barb Tipple blending and coal crushing facility, Conesville preparation plant and truck scale. This mining complex produced no coal for the year ended December 31, 2013.

Belmont Mining Complex

The Belmont mining complex is located in Belmont County, Ohio, and currently consists of the Bedway-Kaczor, Egypt Valley, Pickens and Wheeling Valley mines. We began mining operations at this mining complex in 1999. Operations at the Belmont mining complex target the Pittsburgh #8 and Meigs Creek #9 coal seams. As of December 31, 2013, the Belmont mining complex included 11.9 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, and auger methods of surface mining. This mining complex produced 1.0 million tons of coal for the year ended December 31, 2013.

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 mining operations at this mining complex in 1993. Operations at the New Lexington mining complex target the Lower Kittanning #5 and Middle Kittanning #6 coal seams. As of December 31, 2013, the New Lexington mining complex included 7.3 million tons of proven and probable coal reserves. 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 or to our Barb Tipple. Some of the coal production from this mining complex is trucked to our Conesville preparation plant and then transported by truck to the customer. This mining complex uses the area, and auger method of surface mining. The infrastructure at this mining complex includes a coal crusher, a truck scale and the New Lexington rail loadout. This mining complex produced 0.8 million tons of coal for the year ended December 31, 2013.

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 owns the remaining 49% indirectly through one of its subsidiaries. We entered into this joint venture in 2007 to mine coal reserves purchased from CONSOL. 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, 2013 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. We believe that CONSOL controls additional reserves in Harrison County, Ohio, that could be acquired by Harrison Resources in the future. However, CONSOL 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 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, 2013, the Harrison mining complex included 3.0 million tons of proven and probable coal reserves. 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. The infrastructure at this mining complex includes a coal crusher and a truck scale. This mining complex uses the area method of surface mining. This mining complex produced 0.7 million tons of coal for the year ended December 31, 2013.

Noble Mining Complex

The Noble mining complex is located in Noble and Guernsey Counties, Ohio, and currently consists of the King-Crum mine. We began mining operations at this complex in 2006. Operations at the Noble mining complex target the Pittsburgh #8 and Meigs Creek #9 coal seams. As of December 31, 2013, the Noble mining complex included 1.6 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 mining complex uses the area, contour and auger methods of surface mining. This mining complex produced 0.2 million tons of coal for the year ended December 31, 2013.

Illinois Basin

The following map shows the locations of our Illinois Basin mining operations and coal reserves and related transportation infrastructure as of December 31, 2013.

In 2013, we operated one surface mining complex in the Illinois Basin, located in western Kentucky, which was idled in December 2013. For the year ended December 31, 2013, this mining complex produced an aggregate of 0.3 million tons of thermal coal. The following table provides summary information regarding our mining complex in the Illinois Basin for the years indicated.

Muhlenberg Mining Complex

The Muhlenberg mining complex, located in Muhlenberg and McLean Counties in western Kentucky, consisted of the Schoate (Briar Hill) mine. We began mining operations at this mining complex in October 2009. Operations at the Muhlenberg mining complex target the #5, #6, #9, #10, #11, #12 and #13 coal seams of the Illinois Basin. As of December 31, 2013, the Muhlenberg mining complex included 16.3 million tons of proven and probable coal reserves. Coal produced from this mining complex was 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 was then transported to the customer by barge. This mining complex used the area method of surface mining. The infrastructure at this mining complex includes one coal crusher, two truck scales and our Island river terminal. This mining complex produced 0.3 million tons of thermal coal during the year ended December 31, 2013.

As of December 31, 2013, all Illinois Basin production has been idled, with the redeployment of the remaining Illinois Basin equipment to our Northern Appalachian operations expected to culminate during the first quarter of 2014. We expect these remaining restructuring efforts to cost an additional $ 0.1 million. Additionally, we are seeking to sell the remaining Illinois Basin equipment, consisting of a large-capacity shovel and several smaller pieces of equipment, and would consider offers for the remaining coal reserves and/or facilities related to the Illinois Basin operations.

Preparation Plants and Blending Facilities

Depending on coal quality and customer requirements, most coal is crushed and shipped directly from the 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. Coal of various sulfur and ash contents can be mixed or “blended” to meet the customers’ specific combustion and environmental needs. Blending is typically done at one of our five blending facilities:

In December 2013, all Illinois Basin operations have been idled , including our Island river terminal and transloading facility on the Green River in western Kentucky.

Underground Coal Reserves

We began underground mining at the Tusky mining complex in late 2003 after leasing coal reserves from a third party in exchange for a royalty based on tons sold. In June 2005, we sold the Tusky mining complex, and subleased the associated underground coal reserves to the purchaser in exchange for a royalty. There are 9 years remaining on our lease for the underground coal reserves, and the related sublease. The sublessee has the option at any time after December 31, 2022 to elect to have Oxford assign its interest as “Lessee” and “Sublandlord” to the sublessee for defined and predetermined consideration. For the year ended December 31, 2013, we recognized less than $0.1 million in royalty on the sublease of the Tusky mine.

Other Operations

Brokered coal sales

In addition to the coal we mine, we purchase and resell coal produced by third parties to fulfill certain sales obligations.

Limestone

At our Daron, Pickens, and Strasburg mines, we remove limestone so that we can access the underlying coal. We sell this limestone to a third party that crushes the limestone before selling it 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 the limestone sales. For the year ended December 31, 2013, we produced and sold 1.5 million tons of limestone, and our revenues included $5.1 million in limestone sales.

Other Operations

For the fiscal year ended December 31, 2013, we generated $5.5 million of revenue from a variety of other activities 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 Part III, Item 13 - Certain Relationships and Related Transactions, and Director Independence .

Customers

Our primary customers are electric utility companies, predominantly operating in our six-state market area, that purchase coal under long-term coal sales contracts. Substantially all of our customers purchase coal for terms of one year or longer, but we also supply coal on a short-term or spot market basis for some of our customers. For the year ended December 31, 2013, we derived approximately 93.9% of our total coal revenues from sales to our ten largest customers, with affiliates of the following top three customers accounting for approximately 74.1% of our coal revenues for that period: American Electric Power Company, Inc. (42.2%); FirstEnergy Corp. (20.0%); and East Kentucky Power Cooperative (12.0%), with a portion of these sales being facilitated by coal brokers.

Long-term Coal Supply Contracts

As is customary in the coal industry, we enter into long-term supply contracts (one year or greater in duration) with substantially all of our customers. These contracts allow customers to secure a supply for their future needs and provide us with greater predictability of sales volumes and prices. For the year ended December 31, 2013, approximately 96.7% of our coal tons sold were sold under long-term supply contracts. We sell the remainder of our coal through short-term contracts and on the spot market.

The terms of our coal supply contracts result from competitive bidding and extensive negotiations with each customer. Consequently, the terms can vary significantly by contract, and can cover such matters as price adjustment features, price reopener terms, coal quality requirements, quantity adjustment mechanisms, permitted sources of supply, future regulatory changes, extension options, force majeure provisions and termination and assignment provisions. Some long-term contracts provide for a pre-determined adjustment to the stipulated base price at specified times or periodic intervals to account for changes due to inflation or deflation in prevailing market prices.

In addition, most contracts contain provisions to adjust the base price due to new statutes, ordinances or regulations that influence our costs of production. In addition, some of our contracts contain provisions that allow for the recovery of costs impacted by modifications or changes in the interpretations or application of applicable government statutes.

Price reopener provisions are present in several of our long-term contracts. These price reopener provisions may automatically set a new price based on prevailing market price or, in some instances, require the parties to agree on a new price, sometimes within a specified range. In a limited number of contracts, failure of the parties to agree on a price under a price reopener provision can lead to termination of the contract.

Quality and volume are stipulated in the coal supply contracts. In some instances, buyers have the option to change annual or monthly volumes. Most of our coal supply contracts contain provisions that require us to deliver coal with specific characteristics, such as heat content, sulfur, ash, hardness and ash fusion temperature, that fall within certain ranges. Failure to meet these specifications can result in economic penalties, suspension or cancellation of shipments or termination of the contract.

Supplies

In 2013, we spent more than $134.9 million to procure goods and services in support of our operating business activities, excluding capital expenditures. Principal commodities include repair and maintenance parts and services, fuel, explosives, tires and lubricants. Outside suppliers perform a significant portion of our on- and off-site equipment rebuilds and repairs as well as construction and reclamation activities.

Each of our mining operations has developed its own supplier base consistent with local needs. Additionally, we have a centralized sourcing group for major supplier contract negotiation and administration, and for the negotiation and purchase of major capital goods. Our supplier base has been relatively stable for many years; however, there has been some consolidation. We are not dependent on any one supplier in any region. We promote competition between suppliers and seek to develop relationships with suppliers that focus on lowering our costs. We also seek suppliers who identify and concentrate on implementing continuous improvement opportunities within their area of expertise.

Competition

The markets in which we sell our coal are highly competitive. We compete directly with other coal producers and indirectly with producers of other energy products that provide an alternative to coal. While we do not compete with producers of metallurgical coal or lignite, we do have limited competition from producers of Power River Basin coal (sub-bituminous coal) in our target market area for bituminous coal. We compete on the basis of delivered price, coal quality and reliability of supply. Our principal direct competitors are other coal producers, including (listed alphabetically) Alliance Resource Partners, L.P., Alpha Natural Resources, Arch Coal, Inc., CONSOL, Foresight Energy, Hallador Energy Company, James River Coal Company, Murray Energy Corp., Patriot Coal Corporation, Peabody Energy Corp., Rhino Resource Partners, L.P. and various other smaller, independent producers.

Demand for coal and the prices that we are able to obtain are closely linked to coal consumption patterns of the domestic electric generation industry. Coal fueled approximately 39.1 % of domestic electric generation in 2013, and this is projected by the EIA to increase to 40.2% in 2014. Coal consumption patterns are influenced by factors beyond our control including the demand for electricity, which is significantly dependent upon economic activity, weather patterns in the United States, government regulation, technological developments, the location, availability, quality and price of competing sources of coal, changes in international supply and demand, alternative fuels such as natural gas, oil, nuclear and alternative energy sources such as hydroelectric power.

Reclamation

Reclamation expenses are a significant part of any coal mining operation. Prior to commencing mining operations, a company is required to apply for numerous permits in the state where the mining is to occur. Before a state will approve and issue these permits, it requires the mine operator to present a reclamation plan which meets regulatory criteria and to secure a surety bond to guarantee reclamation funding in an amount determined under state law. Bonding companies require posting of collateral, typically in the form of letters of credit to secure the bonds. As of December 31, 2013, we had $9.6 million in cash deposits supporting $37.0 million in reclamation surety bonds. While bonds are issued against reclamation liability for a particular permit at a particular site, collateral posted in support of the bond is not allocated to a specific bond, but instead is part of a collateral pool supporting all bonds issued by a particular bonding company. Bonds are released in phases as reclamation is completed in a particular area.

Environmental, Safety and Other Regulatory Matters

Federal, state and local authorities regulate the United States coal mining industries with respect to matters such as: employee health and safety; permitting and licensing requirements; emissions to air; discharges to water; plant and wildlife protection; the reclamation and restoration of properties after mining or other activity has been completed; the storage, treatment and disposal of wastes; remediation of contaminated soil; protection of surface and groundwater; surface subsidence from underground mining; the effects on surface and groundwater quality and availability; noise; dust and competing uses of adjacent, overlying or underlying lands such as for oil and gas activity, pipelines, roads and public facilities. Ordinances, regulations and legislation (and judicial or agency interpretations thereof) with respect to these matters have had, and will continue to have, a significant effect on our production costs and our competitive position. New laws and regulations, as well as future interpretations or different enforcement of existing laws and regulations, may require substantial increases in equipment and operating costs and may cause delays, interruptions, or a termination of operations, the extent of which we cannot predict. We intend to respond to these regulatory requirements and interpretations thereof at the appropriate time by implementing necessary modifications to facilities or operating procedures or plans. When appropriate, we may also challenge actions in regulatory or court proceedings. Future legislation, regulations, interpretations or enforcement may also cause coal to become a less attractive fuel source for our customers due to factors such as investments in pollution control equipment necessary to meet new and more stringent air, water or solid waste requirements. Similarly, coal may become a less attractive fuel source for our customers if federal, state or local emissions rates or caps on greenhouse gases (“GHGs”) are enacted, or a tax on carbon is imposed, such as those that may result from climate change legislation or regulations. As a result, future legislation, regulations, interpretations or enforcement may adversely affect our mining or other operations, or our cost structure or may adversely impact the ability or economic desire of our customers to use coal.

We endeavor to conduct our mining and other operations in compliance with all applicable federal, state, and local laws and regulations. However, due in part to the extensive and comprehensive regulatory requirements, violations occur from time to time. It is possible that future liability under or compliance with environmental and safety requirements could have a material effect on our operations or competitive position. Under some circumstances, substantial fines and penalties, including revocation or suspension of mining or other permits or plans, may be imposed under the laws described below. Monetary sanctions and, in severe circumstances, criminal sanctions may be imposed for failure to comply with these laws.

Mine Safety and Health

The Coal Mine Health and Safety Act of 1969 and the Federal Mine Safety and Health Act of 1977 impose stringent safety and health standards on all aspects of mining operations. Also, the states in which we operate have state programs for mine safety and health regulation and enforcement. Collectively, federal and state safety and health regulation in the coal mining industry is perhaps one of the most comprehensive and pervasive systems for protection of employee health and safety affecting any segment of U.S. industry. Regulation has a significant effect on our operating costs.

In recent years, legislative and regulatory bodies at the state and federal levels, including the U.S. Mine Safety and Health Administration (“MSHA”), have promulgated or proposed various statutes, regulations and policies relating to mine safety and mine emergency issues. The Mine Improvement and New Emergency Response (“MINER”) Act passed in 2006 mandated mine rescue regulations, new and improved technologies and safety practices in the area of tracking and communication, and emergency response plans and equipment. Although some new laws, regulations and policies are in place, these legislative and regulatory efforts are still ongoing.

Subsequent to passage of the MINER Act, Illinois, Kentucky, Pennsylvania and West Virginia have enacted legislation addressing issues such as mine safety and accident reporting, increased civil and criminal penalties, and increased inspections and oversight. In January 2012, West Virginia began consideration of additional mine safety legislation. Other states may pass similar legislation in the future.

At this time, it is not possible to predict the full effect that new or more stringent safety and health requirements will have on our operating costs.

In 2010, Congress expanded mine safety disclosure requirements pursuant to Section 1503 of the Dodd-Frank Wall Street Reform and Consumer Protection Act (the “Dodd-Frank Act”). In December 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. The new rules, which became effective in January 2012, require disclosure of the total number of health or safety-related violations, citations, orders, notices, assessments, fatalities and legal actions on a mine-by-mine basis. The information concerning mine safety violations or other regulatory matters required by Section 1503(a) of the Dodd-Frank Act and Item 104 of Regulation S-K is included in "Exhibit 95, Mine Safety Disclosure."

Mining Permits and Approvals

Numerous governmental permits, licenses or approvals are required for mining operations. When we apply for these permits and approvals, we may be required to present data to federal, state or local authorities pertaining to the effect or impact our operations may have upon the environment. The requirements imposed by any of these authorities may be costly and time consuming and may delay commencement or continuation of mining or other operations. These requirements may also be supplemented, modified or re-interpreted from time to time. Regulations also provide that a mining permit or modification can be delayed, refused or revoked if an officer, director or a stockholder with a 10% or greater interest in the entity is affiliated with or is in a position to control another entity that has outstanding permit violations. Thus, past or ongoing violations of federal and state mining laws could provide a basis to revoke existing permits and to deny the issuance of additional permits.

In order to obtain mining permits and approvals from state regulatory authorities, we must submit a reclamation plan for restoring, upon the completion of mining operations, the mined property to its prior or better condition, productive use or other permitted condition. Typically, we submit our necessary permit application several months, or even years, before we plan to begin mining. However, in the current environment with enhanced scrutiny by regulators, increased opposition by environmental groups and others and potential resultant delays, we now anticipate that mining permit approvals will take even longer than previously experienced, and some permits may not be issued at all.

Surface Mining Control and Reclamation Act

The Federal Surface Mining Control and Reclamation Act of 1977 (“SMCRA”) and similar state statutes establish operational, reclamation and closure standards for all aspects of surface mining, as well as many aspects of underground mining. SMCRA requires that comprehensive environmental protection and reclamation standards be met during the course of and upon completion of our mining activities.

SMCRA and similar state statutes require, among other things, that mined property be restored in accordance with specified standards and approved reclamation plans. SMCRA requires us to restore the surface to approximate the original contours as contemporaneously as practicable with the completion of surface mining operations. Federal law and some states impose on mine operators the responsibility for replacing certain water supplies damaged by mining operations and repairing or compensating for damage to certain structures occurring on the surface as a result of mine subsidence, a consequence of longwall mining and possibly other mining methods. We believe we are in compliance in all material respects with applicable regulations relating to reclamation.

Some SMCRA mine permits take over a year to prepare, depending on the size and complexity of the mine. Once a permit application is prepared and submitted to the regulatory agency, it goes through a completeness review and technical review. Proposed permits also undergo a public notice and comment period. Some SMCRA mine permits may take several years or even longer to be issued. Regulatory authorities have considerable discretion in the timing of the permit issuance and the public and other agencies have rights to comment on and otherwise engage in the permitting process, including through intervention in the courts.

In addition, the Abandoned Mine Lands Program, which is part of SMCRA, imposes a tax on all current mining operations, the proceeds of which are used to restore mines closed before 1977. The tax for surface-mined coal is $0.315 per ton from 2008 to 2012, with a reduction to $0.28 per ton from 2013 to 2021. In addition, states from time to time have increased and may continue to increase their fees and taxes to fund reclamation on orphaned mine sites and acid mine drainage (“AMD”) control on a statewide basis.

In December 2008, the OSM issued revisions to its Stream Buffer Zone Rule (“SBZ Rule”) under SMCRA. The SBZ Rule prohibits mining disturbances within 100 feet of streams, if there would be a negative effect on water quality. Environmental groups brought lawsuits challenging the rule, and in a March 2010 settlement, the OSM agreed to propose a new SBZ Rule by February 28, 2012 and publish a final rule by June 29, 2012. To date, the OSM has not proposed a new SBZ Rule. Congressional investigations into a draft Environmental Impact Statement and Regulatory Impact Analysis released in January 2011, indicating that 7,000 coal mining jobs would be lost from the Administration’s rewriting of the SBZ Rule as a new Stream Protection Rule, has stalled OSM’s initiative. In addition, Congress has proposed, and may in the future propose, legislation to restrict the placement of mining material in streams. The requirements of a new Stream Protection Rule or future legislation, if adopted, will likely be stricter than the existing SBZ Rule and may adversely affect our business and operations.

Surety Bonds

Federal and state laws require us to obtain surety bonds to secure payment of certain long-term obligations including mine closure or reclamation costs, water treatment, federal and state workers' compensation costs, obligations under federal coal leases and other miscellaneous obligations. Many of these bonds are renewable on a yearly basis.

Air Emissions

The federal Clean Air Act (“CAA”) and similar state and local laws and regulations regulate emissions into the air and affect coal mining operations. The CAA directly impacts our coal mining and processing operations by imposing permitting requirements and, in some cases, requirements to install certain emissions control equipment, achieve certain emissions standards, or implement certain work practices on sources that emit various air pollutants. The CAA also indirectly affects coal mining operations by extensively regulating the air emissions of coal-fired electric power generating plants and other coal-burning facilities. There have been a series of federal rulemakings focused on emissions from coal-fired electric generating facilities. In addition, there is pending litigation to force the U.S. Environmental Protection Agency (“EPA”) to list coal mines as a category of air pollution sources that endanger public health or welfare under Section 111 of the CAA and establish standards to reduce emissions from new or modified coal mine sources of methane and other emissions. Installation of additional emissions control technology and any additional measures required under the laws, as well as regulations promulgated by the EPA, will make it more costly to operate coal-fired power plants and could make coal a less attractive fuel alternative in the planning and building of power plants in the future.

In addition to the GHG issues discussed below, the air emissions programs that may affect our operations, directly or indirectly, include, but are not limited to, the following:

Climate Change 

Combustion of fossil fuels, such as the coal we produce, results in the emission of carbon dioxide and other GHGs which have been subject to public and regulatory concern with respect to climate change or global warming. Current and future regulation of GHGs may occur on various international, federal, state and local levels, including pursuant to future legislative action, EPA enforcement under the CAA, state laws, regional initiatives, and court orders.

Congress has actively considered proposals in the past several years to reduce GHG 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 affect 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 GHG emissions under the CAA 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 GHG emissions, under the CAA 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 source. The tailoring rule increased this threshold for GHG emissions to 75,000 tons per year starting January 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.

Moreover, in October 2009, the EPA issued a final rule requiring certain emitters of GHGs, including coal-fired power plants, to monitor and report their annual GHG 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.

In January 2014, the EPA published proposed new source performance standards for emissions of carbon dioxide for new fossil fuel-fired electric utility generating units. The proposed requirements, which are limited to new sources, require new fossil fuel-fired electric utility generating units greater than 25 megawatts to meet an output-based standard of 1,000 pounds of CO2 per megawatt-hour, based on the availability of natural gas combined cycle technology. No existing or proposed coal-fired electric utility generating units can meet this standard.

In some areas, carbon dioxide emissions are subject to state and regional regulation. For example, the Regional Greenhouse Gas Initiative (“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 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. Other current and proposed GHG 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.

In June 2011, the U.S. Supreme Court ruled in American Electric Power Co., Inc. v. Connecticut that corporations cannot be sued for public nuisance based upon global warming allegedly caused by out-of-state emissions from fossil-fuel fired power plants under federal common law, primarily because the CAA delegates the management of carbon dioxide and other GHG emissions to the EPA.

In addition to direct regulation of GHGs, 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 GHG emissions. 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 (“CWA”), and corresponding state 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:

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 in February 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. In August 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 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 mountaintop 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, in April 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 (“NMA”), the State of West Virginia, and the Kentucky Coal Association and other plaintiffs challenged the EPA’s Enhanced Coordination Process and interim detailed guidance in National Mining Association v. Jackson, et. al (D.D.C.). In July 2011, the EPA issued its Final Guidance document mooting the challenge to the EPA’s interim guidance; however, the District Court allowed the complaints to be amended setting up the proceedings for a final ruling. In October 2011, in granting plaintiffs’ partial motion for summary judgment, 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 of the Administrative Procedures Act. In July 2012, the District Court granted summary judgment on behalf of the plaintiffs overturning the Final Guidance and finding that the EPA overstepped its statutory authority under the CWA and SMCRA, and infringed on the authority afforded state regulators by those statutes in issuing the guidance. EPA filed appeals of lower courts’ decisions to Washington D.C. Circuit Court of Appeals. All of the briefs have been filed; including amici curiae briefs in support of NMA, the State of West Virginia and Kentucky Coal Association from a coalition of the states’ attorneys general and an industry group; and oral arguments took place in February 2014.

In February 2012, the Corps reauthorized and substantially modified NWP 21, limiting wetland impacts to ½ acre and stream impacts to 300 linear feet, as well as prohibiting its use to authorize valley fills associated with surface coal mining activities. The District Engineer, of the Corps, may waive the threshold limits of NWP if the discharge results in minimal individual and cumulative adverse effects on the aquatic environment. The 1⁄2-acre and 300 linear foot limits will substantially limit the utility of NWP 21 for surface coal mining activities.

However, in April 2013, the Sixth Circuit Court of Appeals in Kentucky Riverkeeper, Inc. v. Rowlette, 714 F.3d 402 (6th Cir. Ky. 2013), invalidated NWP 21 on the ground that the Corps had failed to prepare a required environmental impact statement.  Upon remand, the District Court for the Eastern District of Kentucky subsequently held that any project authorization in Kentucky under the vacated NWP 21 is invalid and must be set aside

Despite these rulings and the reauthorization of NWP 21, the EPA continues to make permitting for Appalachian surface coal mining activities more difficult, increase the regulatory burdens imposed on such projects, extend the time required to obtain permits and in general increase 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.

In April 2013, the Washington D.C. Circuit Court of Appeals in Mingo Logan Coal Co (Mingo Logan). v. United States Environmental Protection Agency (714 F.3d 608, ELR 20094, No. 12-5150) reversed Washington D.C. District Court’s decision (850 F. Supp. 2d 133) that EPA exceeded its authority under CWA §404(c) when in 2010, EPA invalidated a 2007 U.S. Army Corps of Engineer permit issued to an Arch Coal, Inc. subsidiary, Mingo Logan, Spruce No. 1 mine authorizing impacts to waters of the United States after a 10-years environmental permitting process. The Washington D.C. District Court ruled that CWA §404 does not give EPA the power to render a permit invalid once it has been issued by the Corps . While acknowledging that Mingo Logan’s permit only expressly granted the Corps the power to suspend, modify or revoke it, and that the Corps denied EPA’s requests to do so, the appellate court nevertheless found that “Section 404 imposes no temporal limit on [EPA’s] authority to withdraw the Corps’ specification, but instead expressly empowers [it] to prohibit, restrict or withdraw the specification “ whenever ’ [it] makes a determination that the statutory “unacceptable adverse effect’ will result.” Because the lower court held that EPA did not have the underlying authority to retroactively veto a CWA Sec. 404 permit, it did not address the issue of whether EPA’s withdrawal or retroactive veto of the permit was lawful. The appellate court therefore, remanded this issue to district court. The appellate court decision creates more regulatory uncertainty for businesses required to obtain permits under the CWA in an already difficult permitting environment. After denial of a petition for rehearing en banc and extending the time to file, in November 2013 Mingo Logan filed petitioned the U.S. Supreme Court for writ of certiorari for a hearing on the merits of its appeal. In December 2013, the State of West Virginia and 26 other states (including Ohio) filed amici curiae briefs in support of Mingo Logan.

Black Lung Benefits Act

Under the Black Lung Benefits Revenue Act of 1977 and the Black Lung Benefits Reform Act of 1977, as amended in 1981 (collectively “BLBA”), each coal mine operator must secure payment of federal black lung benefits to claimants who are current and former employees to a trust fund for the payment of benefits and medical expenses to eligible claimants. The trust fund is funded by an excise tax on production of up to $0.55 per ton for surface-mined coal, not to exceed 4.4% of the gross sales price. In 2013, we recognized $3.2 million of expense related to this excise tax.

Revised BLBA regulations took effect in January 2001, relaxing the stringent award criteria established under previous regulations and thus potentially allowing more new federal claims to be awarded and allowing previously denied claimants to re-file under the revised criteria. These regulations may also increase black lung related medical costs by broadening the scope of conditions for which medical costs are reimbursable and increase legal costs by shifting more of the burden of proof to the employer.

The Patient Protection and Affordable Care Act (“PPACA”), signed into law in March 2010, includes provisions, retroactive to 2005, which would (1) provide 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, or black lung, and (2) establish 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.

Workers’ Compensation

Workers’ compensation is a system by which individuals who sustain injuries due to job-related accidents are compensated for their disabilities, medical costs and, on some occasions, for the costs of their rehabilitation, and by which survivors of workers who suffer fatal injuries receive compensation for lost financial support. State agencies administer workers’ compensation laws, with each state having its own rules and regulations. Our operations are covered through state-sponsored programs or an insurance carrier where there is no state-sponsored program.

 Comprehensive Environmental Response, Compensation and Liability Act

The Federal Comprehensive Environmental Response, Compensation and Liability Act (“CERCLA”), otherwise known as the “Superfund” law, and analogous state laws, impose liability, without regard to fault or the legality of the original conduct on certain classes of persons that are considered to have contributed to the release of a “hazardous substance” into the environment. These persons include the owner or operator of the site where the release occurred and companies that disposed or arranged for the disposal of the hazardous substances found at the site. Persons who are or were responsible for the release of hazardous substances may be subject to joint and several liability under CERCLA for the costs of cleaning up releases of hazardous substances and natural resource damages. Some products used in coal mining operations generate waste containing hazardous substances. We are currently unaware of any material liability associated with the release or disposal of hazardous substances from our past or present mine sites.

Resource Conservation and Recovery Act 

The Resource Conservation and Recovery Act (“ RCRA”) affects coal mining operations by establishing requirements for the treatment, storage, and disposal of hazardous wastes. Certain coal mine wastes, such as overburden and coal cleaning wastes, are exempted from hazardous waste management requirements.

At present, fossil fuel combustion wastes are exempt from hazardous waste regulation under RCRA. However, the failure in 2008 of an ash disposal dam in Tennessee focused attention on this issue. In May 2010, the EPA issued for public comment proposed regulations setting out two options for governing management and disposal of coal ash from coal-fired power plants. Under the more stringent option, the EPA would regulate coal ash as a “special waste” subject to RCRA Subtitle C hazardous waste standards when disposed in landfills or surface impoundments, which would be subject to stringent design, permitting, closure and corrective action requirements. Alternatively, coal ash would be regulated as non-hazardous waste under RCRA Subtitle D, with national minimum criteria for disposal but no federal permitting or enforcement. Under both options, the EPA would establish dam safety requirements to address the structural integrity of surface impoundments to prevent catastrophic releases. We currently cannot predict whether these rules, once finalized, will have a significant impact on coal used by electricity generators.

Endangered Species Act

The federal Endangered Species Act and counterpart state legislation protect species threatened with possible extinction. Protection of threatened and endangered species may have the effect of prohibiting or delaying us from obtaining mining permits and may include restrictions on timber harvesting, road building and other mining or agricultural activities in areas containing the affected species or their habitats. While a number of species indigenous to our properties are protected under the Endangered Species Act, based on the species identified to date and the current application of applicable laws and regulations, we do not believe there are any that would have a material and adverse effect on our ability to mine coal in accordance with current mining plans.

Other Environmental, Health And Safety Regulations

In addition to the laws and regulations described above, we are subject to regulations regarding underground and above ground storage tanks in which we may store petroleum or other substances. Some monitoring equipment that we use is subject to licensing under the Federal Atomic Energy Act. Water supply wells located on our properties are subject to federal, state, and local regulation. We are also required to comply with the Safe Drinking Water Act, the Toxic Substance Control Act, and the Emergency Planning and Community Right-to-Know Act. In addition, our use of explosives is subject to the Federal Safe Explosives Act.

Employees

As of December 31, 2013, we employed 638 full-time employees to conduct our operations, including 494 employees involved in active mining operations, 112 employees in other operations, and 32 corporate employees. Our workforce is entirely union-free. 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.

Additional Information

We file annual, quarterly and current reports, as well as amendments to those reports, and other information with the SEC. You may access and read our SEC filings without charge through our website, http://www.OxfordResources.com , or the SEC’s website, http://www.sec.gov . You may also read and copy any document we file at the SEC’s public reference room located at 100 F Street, N.E., Room 1580, Washington, D.C. 20549. Please call the SEC at (800) SEC–0330 for further information on the public reference room. 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.

GLOSSARY OF SELECTED TERMS

Ash : Impurities consisting of silica, alumina, calcium, iron and other noncombustible matter that are contained in coal. Since ash increases the weight of coal, it adds to the cost of handling and can affect the burning characteristics of coal.

Bituminous coal : A middle rank coal formed by additional pressure and heat on lignite. It is the most common type of coal with moisture content less than 20% by weight and heating value of 9,500 to 14,000 Btus per pound. It is dense and black and often has well-defined bands of bright and dull material. It may be referred to as soft coal.

British thermal unit or Btu : A measure of the thermal energy required to raise the temperature of one pound of pure liquid water one degree Fahrenheit at the temperature at which water has its greatest density (39 degrees Fahrenheit). On average, coal contains about 11,000 Btu per pound.

Byproduct : Useful substances made from the gases and liquids left over when coal is made into coke.

Coal seam : A bed or stratum of coal, usually applies to a large deposit.

Compliance coal : Coal which, when burned, emits 1.2 pounds or less of sulfur dioxide per million Btu, as required by Phase II of the Clean Air Act Acid Rain program.

Continuous miner : A machine that simultaneously extracts and loads coal. This is distinguished from a conventional, or cyclic, unit, which must stop the extraction process for loading to commence.

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

Fossil fuel : Fuel such as coal, crude oil or natural gas formed from the fossil remains of organic material.

High-Btu coal : Coal which has an average heat content of 12,500 Btus per pound or greater.

High-sulfur coal : Coal which, when burned, emits 2.5 pounds or more of sulfur dioxide per million Btu.

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.

Lignite : The lowest rank of coal with a high moisture content of up to 15% by weight and heat value of 6,500 to 8,300 Btus per pound. It is brownish black and tends to oxidize and disintegrate when exposed to air.

Illinois Basin : Coal producing area in Illinois, Indiana and western Kentucky.

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.

Nitrogen oxide (NOx): A gas formed in high temperature environments, such as coal combustion, that is a harmful pollutant and contributes to acid rain.

Northern Appalachia : Coal producing area in Maryland, Ohio, Pennsylvania and northern West Virginia.

Overburden : Layers of earth and rock covering a coal seam, that in surface mining operations must be removed prior to coal extraction.

Preparation plant : A facility for crushing, sizing and washing coal to prepare it for use by a particular customer. The washing process has the added benefit of removing some of the coal’s sulfur content. While usually located on a mine site, one plant may serve multiple mines.

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.

Recoverable reserve : The amount of coal that can be extracted from the Reserves. The recovery factor for surface mines is typically between 80% and 90%.

Reserve : That part of a mineral deposit that could be economically and legally extracted.

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).

Strip ratio : Strip ratio refers to the number of bank cubic yards of overburden or waste that must be removed to extract one ton of coal.

Sub-bituminous Coal: Dull coal that ranks between lignite and bituminous coal. Its moisture content is between 20% and 30% by weight and its heat content ranges from 7,800 to 9,500 Btus per pound.

Sulfur : One of the elements present in varying quantities in coal and which contributes to environmental degradation when coal is burned. Sulfur dioxide is produced as a gaseous byproduct of coal combustion.

Tipple : A structure where coal is loaded in railroad cars or trucks.

Thermal coal (aka Steam coal) : Coal burned by electric power plants and industrial steam boilers to produce electricity, steam or both.

Tons : A “short,” or net, ton is equal to 2,000 pounds. A “long,” or British, ton is equal to 2,240 pounds. A “metric” ton is approximately 2,205 pounds. The short ton is the unit of measure referred to in this report.

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.