10-K

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

Form 10-K

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

For the fiscal year ended December 31, 2013

OR

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

For the transition period from        to  

COMMISSION FILE NO.: 001-34815

Oxford Resource Partners, LP

(Exact name of registrant as specified in its charter)

Delaware	77-0695453
(State or other jurisdiction of incorporation or organization)	(I.R.S. Employer Identification Number)

41 South High Street, Suite 3450, Columbus, Ohio 43215

(Address of principal executive offices and zip code)

(614) 643-0314

(Registrant’s telephone number, including area code)

Securities registered pursuant to Section 12(b) of the Act: Common Units representing limited partner interests

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

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

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

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

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

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

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

Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, or a smaller reporting company. See the definitions of “large accelerated filer,” “accelerated filer,” and “smaller reporting company” in Rule 12b-2 of the Exchange Act. (Check one)

Large Accelerated Filer	☐	Accelerated Filer	☐
Non-Accelerated Filer	☒	Smaller Reporting Company	☐

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

The aggregate market value of the common units held by non-affiliates of the registrant (treating all executive officers and directors of the registrant, for this purpose, as if they may be affiliates of the registrant) was $24,791,000 as of June 30, 2013, based on the reported closing price of the common units as reported on the New York Stock Exchange on June 28, 2013.

As of February 28, 2014, 10,589,149 common units and 10,280,380 subordinated units were outstanding. The common units trade on the New York Stock Exchange under the ticker symbol “OXF.”

DOCUMENTS INCORPORATED BY REFERENCE: None

TABLE OF CONTENTS

		Page
Cautionary Statement About Forward-Looking Statements		1
PART I
Item 1.	Business	3
	Glossary of Selected Terms	25
Item 1A.	Risk Factors	27
Item 1B.	Unresolved Staff Comments	46
Item 2.	Properties	46
Item 3.	Legal Proceedings	48
Item 4.	Mine Safety Disclosures	48
PART II
Item 5.	Market for Registrant’s Common Equity, Related Unitholder Matters and Issuer Purchases of Equity Securities	49
Item 6.	Selected Financial and Operating Data	51
Item 7.	Management’s Discussion and Analysis of Financial Condition and Results of Operations	54
Item 7A.	Quantitative and Qualitative Disclosures About Market Risk	67
Item8.	Financial Statements and Supplementary Data	68
Item 9.	Changes in and Disagreements With Accountant on Accounting and Financial Disclosure	68
Item 9A.	Controls and Procedures	68
Item 9B.	Other Information	70
PART III
Item 10.	Directors, Executive Officers and Corporate Governance	71
Item 11.	Executive Compensation	76
Item 12.	Security Ownership of Certain Beneficial Owners and Management and Related Unitholder Matters	91
Item 13.	Certain Relationships and Related Transactions, and Director Independence	95
Item 14.	Principal Accountant Fees and Services	98
PART IV
Item 15.	Exhibits and Financial Statement Schedules	99

Cautionary Statement About Forward-Looking Statements

Statements in this Annual Report on Form 10-K that are not historical facts are forward-looking statements within the "safe harbor" provision of the Private Securities Litigation Reform Act of 1995 and may involve a number of risks and uncertainties. We have used the words "anticipate," "believe," "could," "estimate," "expect," "intend," "may," "plan," "predict," "project," and similar terms and phrases, including references to assumptions, in this report to identify forward-looking statements. These forward-looking statements are made based on expectations and beliefs concerning future events affecting us and are subject to various risks, uncertainties and factors relating to our operations and business environment, all of which are difficult to predict and many of which are beyond our control, that could cause our actual results to differ materially from those matters expressed in or implied by these forward-looking statements. The following factors are among those that may cause actual results to differ materially from our forward-looking statements:

• market demand for coal and energy, including changes in consumption patterns by utilities away from the use of coal;

• availability of qualified workers;

• future economic or capital market conditions;

• weather conditions or catastrophic weather-related damage;

• our production capabilities;

• consummation of financing, acquisition or disposition transactions and the effect thereof on our business;

• our plans and objectives for future operations and expansion or consolidation;

• our relationships with, and other conditions affecting, our customers;

• availability and costs of credit, surety bonds and letters of credit;

• our liquidity, including our ability to adhere to financial covenants related to our borrowing arrangements;

• availability and costs of key supplies or commodities, such as diesel fuel, steel, explosives and tires;

• availability and costs of capital equipment;

• prices of fuels which compete with or impact coal usage, such as oil and natural gas;

• timing of reductions or increases in customer coal inventories;

• long-term coal supply arrangements;

• reductions and/or deferrals of purchases by major customers;

• coal mining operations, including risks relating to third-party suppliers and carriers operating at our mines or complexes;

• unexpected maintenance and equipment failure;

• environmental, safety and other laws and regulations, including those directly affecting our coal mining and production, and those affecting our customers' coal usage;

• ability to obtain and maintain all necessary governmental permits and authorizations;

• competition among coal and other energy producers in the United States and internationally;

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• railroad, barge, trucking and other transportation availability, performance and costs;

• employee benefits costs and labor relations issues;

• replacement of our reserves;

• our assumptions concerning economically recoverable coal reserve estimates;

• title defects or loss of leasehold interests in our properties, which could result in unanticipated costs or inability to mine these properties;

• future legislation and changes in regulations or governmental policies or changes in interpretations or enforcement thereof, including with respect to safety enhancements and environmental initiatives relating to global warming and climate change;

• our ability to pay our quarterly distributions which substantially depends upon our future operating performance (which may be affected by prevailing economic conditions in the coal industry), debt covenants, and financial, business and other factors, some of which are beyond our control;

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

• adequacy and sufficiency of our internal controls;

• legal and administrative proceedings, settlements, investigations and claims, including those related to citations and orders issued by regulatory authorities, and the availability of related insurance coverage; and

• the need to recognize additional impairment and/or restructuring expenses associated with our operations, as well as any changes to previously identified impairment or restructuring expense estimates, including additional impairment and restructuring expenses associated with our Illinois Basin operations.

You should keep in mind that any forward-looking statements made by us in this Annual Report on Form 10-K or elsewhere speaks only as of the date on which the statements were made. New risks and uncertainties arise from time-to-time, and it is impossible for us to predict these events or how they may affect us or our anticipated results. We have no duty to, and do not intend to, update or revise the forward-looking statements in this Annual Report on Form 10-K after its issuance, except as may be required by law. In light of these risks and uncertainties, you should keep in mind that any forward-looking statement made in this Annual Report on Form 10-K might not occur.

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PART I

Introduction

This report is both our 2013 Annual Report to unitholders and our 2013 Annual Report on Form 10-K required under the federal securities laws.

Unless the context otherwise indicates, as used in this Annual Report, the terms “Oxford,” “we,” “our,” “us” and similar terms refer to Oxford Resource Partners, LP and its consolidated subsidiaries.

The term “coal reserves” as used in this report means proven and probable reserves that are the part of a mineral deposit that can be economically and legally extracted or produced at the time of the reserve determination as prescribed by Securities and Exchange Commission (“SEC”) rules.

Because certain terms used in the coal industry may be unfamiliar to many investors, we have provided a “Glossary of Selected Terms” at the end of Part I, Item 1.

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.

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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.

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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 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.

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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.

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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.

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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:

			As of December 31, 2013
Mining Complexes	Production for the Year Ended December 31, 2013		Total Proven & Probable Reserves		Proven Reserves(1)		Probable Reserves(2)		Average Heat Value (BTU/lb)		Average Sulfur Content (%)		Primary Transportation Methods
	(in thousands tons)
Surface Mining Operations:
Northern Appalachia
Cadiz		1,920		6,943		6,881		62		11,370		3.3	Barge, Rail
Tuscarawas		936		7,371		7,371		-		11,825		4.2	Truck
Plainfield		296		2,771		2,771		-		11,836		4.4	Truck
Belmont		995		11,923		11,451		472		11,820		4.2	Barge
New Lexington		829		7,314		6,443		871		11,105		4.1	Rail
Harrison(3)		742		2,984		2,830		154		11,287		1.9	Barge, Rail, Truck
Noble		189		1,627		1,610		17		11,242		4.9	Barge, Truck
Illinois Basin (Kentucky)
Muhlenberg		243		16,296		15,165		1,131		11,314		3.6	Barge, Truck
Total Surface Mining
Operations		6,150		57,229		54,522		2,707
Underground Coal Reserves:
Northern Appalachia (Ohio)
Tusky(4)				24,331		18,965		5,366		12,900		2.1
Total Underground Coal
Reserves				24,331		18,965		5,366
Total				81,560		73,487		8,073

(1) Proven (Measured) Reserves. Reserves for which (a) quantity is computed from dimensions revealed in outcrops, trenches, workings or drill holes; grade and/or quality are computed from the results of detailed sampling and (b) the sites for inspection, sampling and measurement are spaced so closely and the geologic character is so well defined that size, shape, depth and mineral content of reserves are well-established.

(2) Probable (Indicated) Reserves. Reserves for which quantity and grade and/or quality are computed form information similar to that used for proven (measured) reserves, but the sites for inspection, sampling and measurement are farther apart. The degree of assurance, although lower than that for proven (measured) reserves, is high enough to assume continuity between points of observation.

(3) The Harrison mining complex is owned by Harrison Resources, our joint venture with CONSOL. We own 51% of Harrison Resources and CONSOL owns the remaining 49% through one of its subsidiaries. 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 U.S. generally accepted accounting principles (“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. Please read “– Mining Operations – Northern Appalachia – Harrison Mining Complex.”

(4) Please read “– Mining Operations – Underground Coal Reserves” for more information about our underground coal reserves at the Tusky mining complex, which we have subleased to a third party in exchange for an overriding royalty.

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Mining Operations

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:

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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:

	Transportation Facilities Utilized		Transportation	Number of Active Mines at December 31,		Tons Produced for the Year Ended December 31,
Mining Complex	River Terminal	Rail Loadout	Method (1)	2013		2013		2012		2011
						(in millions)
Cadiz	Bellaire	Cadiz	Barge, Rail		4		1.9		1.9		1.7
Tuscarawas	—	—	Truck		5		1.2		0.7		0.9
Plainfield	—	—	Truck		-		-		0.4		0.2
Belmont	Bellaire	—	Barge		4		1.0		1.0		1.0
New Lexington	—	New Lexington	Rail		1		0.8		0.9		0.8
Harrison (2)	Bellaire	Cadiz	Barge, Rail, Truck		1		0.7		0.7		0.8
Noble	Bellaire	—	Barge, Truck		1		0.2		0.2		0.4
Total					16		5.8		5.8		5.8

(1) Barge means transported by truck to our Bellaire river terminal and then transported to the customer by barge. Rail means transported by truck to a rail facility and then transported to the customer by rail. Truck means transported to the customer by truck.

(2) The Harrison mining complex is owned by Harrison Resources, our joint venture with CONSOL. We own 51% of Harrison Resources and CONSOL owns the remaining 49% indirectly through one of its subsidiaries. Because the results of operations of Harrison Resources are included in our consolidated financial statements for each December 31 year-end as required by GAAP, coal production attributable to the Harrison mining complex is presented on a gross basis assuming we owned 100% of Harrison Resources. Please read “— Harrison Mining Complex.”

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.

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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.

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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.

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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.

	Transportation Facilities Utilized					Number of		Tons Produced for the Year Ended December 31,
Mining Complex		River Terminal	Rail Loadout		Method(1)	Active Mines at December 31, 2013		2013		2012		2011
								(in millions)
Muhlenberg		Island River		—	Barge, Truck		-		0.3		2.2		1.7

(1) Barge means transported by truck to our Island river terminal and then transported to the customer by barge. Truck means transported to the customer by truck.

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:

• our Barb Tipple blending and coal crushing facility, adjacent to a customer’s power plant near Coshocton, Ohio;

• our Strasburg preparation plant near Strasburg, Ohio;

• our Conesville preparation plant in Coshocton County, Ohio;

• our Bellaire river terminal on the Ohio River in Bellaire, Ohio; and

• our Stone Creek coal crushing facility located in Tuscarawas County, Ohio.

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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:

• the receipt of a one-time payment of $2.4 million for lost coal in connection with granting third-party right-of-way access through a small portion of various mines;

• the receipt of a settlement payment of $2.1 million from a purchase coal supplier to settle a contract dispute;

• service fees of $0.5 million we earned for operating a transloader for a third party that offloads coal from railcars on the Ohio Central Railroad at one of our customer's power plants;

• selling small amounts of clay to Tunnell Hill Reclamation, LLC, a landfill operator and subsidiary of Tunnel Hill Partners, LP, an entity owned by our sponsors totaling $0.3 million; and

• service fees we earned for hauling and disposing of ash at a third party landfill for two municipal utilities totaling $0.2 million.

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.

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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.

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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.

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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.

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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.

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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:

• Acid Rain: Title IV of the Clean Air Act required a two-phase reduction of SO2 emissions by electric utilities. Phase II became effective in 2000 and applies to all coal-fired power plants generating greater than 25 megawatts. The affected electricity generators have sought to meet these requirements mainly by, among other compliance methods, switching to lower sulfur fuels, installing pollution control devices, reducing electricity generating levels or purchasing SO2 emission allowances.

• Sulfur Dioxide and Nitrogen Dioxide: The Clean Air Act requires the EPA to set standards, referred to as National Ambient Air Quality Standards (“NAAQS”), for certain pollutants. Areas that are not in compliance (referred to as “non-attainment areas”) with these standards must take steps to reduce emissions levels. In 2010, the EPA established a new 1-hour NAAQS for sulfur dioxide (“SO2”), and a new 1-hour NAAQS for nitrogen dioxide (“NO2”). Under the Clean Air Act, the new NAAQS generally must be met no later than five years after the EPA designates an area as non-attainment.

• Clean Air Interstate Rule/Cross-State Air Pollution Rule: In 2005, the EPA issued its final Clean Air Interstate Rule (“CAIR”) for further reducing emissions of SO2 and nitrogen oxides (“NOx”) to deal with the interstate transport component of nonattainment with NAAQS. CAIR calls for Texas and 27 states bordering or east of the Mississippi River, and the District of Columbia, to cap their emission levels of SO2 and NOx through an allowance trading program or other system. In July 2011, in response to the court order on CAIR, the EPA issued a new rule to replace CAIR, called the Cross-State Air Pollution Rule (“CASPR”). In December 2011, a federal appellate court issued a stay of CASPR pending judicial review. During the stay, CAIR remained in effect. In August 2012, the U.S. Court of Appeals for the District of Columbia struck down CASPR, finding that it required certain upwind states to reduce their emissions below their respective contributions to nonattainment and that it usurped states' roles in implementing emission reduction strategies. The EPA appealed the matter to the United States Supreme Court, which heard oral arguments in December 2013.

• Mercury and Air Toxics Standards: In December 2011, the EPA issued the Mercury and Air Toxics Standards (“MATS”), which sets technology-based emission limitation standards for mercury and other toxic air pollutants for coal and oil fired electric generating units with a capacity of 25 megawatts (“MW”) or more. Existing units generally have up to four years to comply. The MATS is subject to a pending court challenge in the U.S. Court of Appeals for the District of Columbia Circuit in which arguments were heard in December 2013. Additionally, in April 2013, EPA published a Final Rule regarding reconsideration of MATS and the New Source Performance Standards Rule, referred to as the Utility NSPS, which finalized new source numerical limits for hydrogen chloride, filterable particulate matter (PM), sulfur dioxide, lead, and selenium emissions for all new coal-fired electric generating units (EGUs).  EPA has also finalized mercury limits for those units designated for coal in the greater than or equal to 8300 btu/lb subcategory.  EPA raised these limits for new sources as a result of information received regarding the variability of the best performing EGUs and to more accurately reflect the capabilities of emission control equipment.  The final rule maintained the source trigger date for MATS as May 3, 2011 and new sources were to have complied with the revised MATS emissions standards by April 24, 2013 or upon startup, whichever is later.  The final rule does not affect MATS emissions standards for existing units. The MATS may ultimately require many coal-fired sources to install additional pollution control equipment or to close.

• Fine Particulate Matter: The EPA has established NAAQS for both particulate matter with an aerodynamic diameter less than or equal to 10 microns (“PM10”), and fine particulate matter with an aerodynamic diameter less than or equal to 2.5 microns (“PM2.5”). Over the past decade, the EPA has taken several steps to lower the NAAQS for particulate matter, which is currently being implemented in a number of designated non-attainment areas. Most recently, in December 2012, the EPA issued a final rule to reduce the annual PM2.5 standard, retaining the existing 24-hour PM2.5 standard and the existing PM10 standards. The final rule will trigger a new round of non-attainment designations and ultimately regulation. Meeting the new PM2.5 standard also may require reductions of nitrogen oxide and SO2 emissions.

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• Ozone: The EPA's 1997 NAAQS for ozone, as amended in 2008, is being implemented in a number of designated non-attainment areas. In addition, the EPA proposed a more stringent ozone NAAQS in January 2010, with the EPA's review of the updated science regarding ozone currently scheduled for completion in 2013. Accordingly, emissions control requirements for new and expanded coal-fired power plants and industrial boilers may continue to become more demanding in the years ahead.

• Regional Haze: Under the EPA's regional haze rule designed to protect and to improve visibility at and around national parks, national wilderness areas and international parks, state implementation plans must either require designated facilities to install Best Available Retrofit Technology (“BART”) to reduce emissions that contribute to visibility problems or adopt an emissions trading program or other alternative program that provides greater reasonable progress towards improving visibility. The regional haze program, which the EPA first established in 1999, primarily affects the construction of new coal-fired power plants whose operation may impair visibility at and around federally protected areas. In May 2012, the EPA issued a final rule that would authorize use of the CASPR trading programs in place of source-specific BART for SO2 and/or NOx emissions from power plants, enabling states to avoid further action under their regional haze implementation plans until 2018. Although the status of the final rule is in doubt following the court decision overturning the CASPR, we expect that emission reductions required under other rules will address many, but perhaps not all, of the emission reduction requirements of the regional haze rule.

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.

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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:

• Wastewater Discharge. Section 402 of the CWA regulates the discharge of "pollutants" from point sources into waters of the United States. The National Pollutant Discharge Elimination System (“NPDES”), requires a permit for any such discharge, which in turn typically imposes requirements for regular monitoring, reporting and compliance with performance standards that govern such discharges.

• Special Protections. 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.

• Dredge and Fill Permits. Many mining activities, including the development of settling ponds and other impoundments, require a permit issued under authority of Section 404 of the CWA (Section 404 permit(s)) by the U.S. Army Corps of Engineers (“Corps”), prior to any discharge or placement of "fill" into navigable waters of the United States. The Corps is empowered to issue "nationwide" permits (“NWPs”), for categories of similar filling activities that are determined to have minimal environmental adverse effects in order to save the cost and time of issuing individual permits under Section 404 of the CWA. Using this authority, in 1982 the Corps issued NWP 21, which authorizes the disposal of dredge-and-fill material from mining activities into the waters of the United States. Individual Section 404 permits are required for activities determined to have more significant impacts to waters of the United States.

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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 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.

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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.

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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.

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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”)).

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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.

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Item 1A.     Risk Factors

Risks Related to Our Business

While our partnership agreement requires that we distribute all of our available cash to our unitholders, we have suspended distributions and are currently prohibited from making distributions to our unitholders pursuant to the terms of our credit facilities.

While our partnership agreement requires us to distribute all of our available cash to our unitholders, we have suspended all distributions to our unitholders commencing with the first quarter of 2013.

In June 2013, we closed on $175 million of credit facilities that replaced our previous term loan and revolving credit facility. Our credit facilities preclude us from making unitholder distributions during the term of our credit facilities. Any subsequent refinancing of our credit facilities or any new credit facilities could have similar restrictions.  

During the period of such any suspension and/or prohibition, we establish reserves that reduce our available cash to zero, so that there is no available cash for distribution to our unitholders. We believe this is warranted by business conditions as well.

Under our partnership agreement, arrearage amounts resulting from suspension and/or prohibition of the common units’ distribution accumulate. Arrearage amounts resulting from suspension and/or prohibition of the subordinated units’ distribution do not accumulate. In the future, if and as distributions are made for any quarter, the first priority is to pay the then minimum quarterly distribution to common unitholders. Any additional distribution amounts paid at that time are then paid to common unitholders until the previously unpaid accumulated arrearage amounts have been paid in full. At December 31, 2013, the accumulated arrearage amounts totaled $25.3 million.

Our credit facilities contain operating and financial restrictions that restrict our business and financing activities.

In addition to prohibiting the payment of unitholder distributions, our credit facilities also contain significant restrictions on our ability to incur additional liens or indebtedness, make fundamental changes or dispositions, make changes in the nature of our business, make certain investments, loans or advances, create certain lease obligations, make capital expenditures in excess of a certain amount, enter into transactions with affiliates, issue equity interests, and modify indebtedness, organizational and certain other documents. Our credit facilities also contain covenants requiring us to maintain certain financial ratios. Any subsequent refinancing of our credit facilities or any new credit facilities could have similar restrictions.  

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

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

For more information, please read “Part II, Item 7 - Management's Discussion and Analysis of Financial Condition and Results of Operations—Liquidity and Capital Resources—Credit Facilities.”

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

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

• our ability to obtain additional financing, if necessary, for working capital, capital expenditures (including acquisitions) or other purposes may be impaired or such financing may not be available on favorable terms;

• our ability to meet financial covenants may affect our flexibility in planning for and reacting to changes in our business, including possible acquisition opportunities;

• our need to use a portion of our cash flow to make principal and interest payments will reduce the amount of funds that would otherwise be available for operations and future business opportunities;

• our increased vulnerability to competitive pressures or a downturn in our business or the economy generally; and

• our flexibility in responding to changing business and economic conditions.

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

Certain provisions in our long-term supply contracts may provide limited protection during adverse economic conditions, may result in economic penalties, and/or may permit customers to terminate such contracts.

Price adjustment, "price re-opener" and other similar provisions in our supply contracts may reduce the protection from short-term coal price volatility traditionally provided by such contracts. Price re-opener provisions typically require the parties to agree on a new price. Failure of the parties to agree on a price under a price re-opener provision can lead to termination of the contract. Any adjustment or renegotiations leading to a significantly lower contract price could adversely affect our business, financial condition and/or results of operations.

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

We depend on supply contracts with a few customers for a significant portion of our revenues.

We sell a material portion of our coal under supply contracts. As of December 31, 2013, we had sales commitments for 90.7% of our estimated coal production (including purchased coal to supplement our production) for the year ending December 31, 2014. When our current contracts with customers expire, our customers may decide not to extend existing contracts or enter into new contracts. In each of 2014 and 2015, 1.7 million tons are to be priced based on market indices, and in each of 2015, 2016 and 2017, 2.1 million tons are dependent upon reaching agreement during reopener periods. For the year ended December 31, 2013, we derived 93.9% of our total revenues from coal sales to our ten largest customers (including their affiliates), with our top three customers (including their affiliates) accounting for 74.1% of such revenues.

In the absence of long-term contracts, our customers may decide to purchase fewer tons of coal than in the past or on different terms, including different pricing terms. Negotiations to extend existing contracts or enter into new long-term contracts with those and other customers may not be successful. In addition, interruption in the purchases by or operations of our principal customers could adversely affect our business, financial condition and/or results of operations. Unscheduled maintenance outages at our customers’ power plants and unseasonably moderate weather are examples of conditions that might cause our customers to reduce their purchases. We may have difficulty identifying alternative purchasers of our coal if our existing customers suspend or terminate their contracts.

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For more information, please read “Part I, Item 1 - Business — Customers – Long-term coal supply contracts.”

We depend upon our ability to collect payments from our customers.

Our ability to receive payment for the coal we sell depends on the continued creditworthiness of our customers. Periods of economic volatility and tight credit markets increase the risk that we may not be paid.

If the creditworthiness of a customer declines, this would increase the risk that we may not be able to collect payment for some or all of the coal we delivered to that customer. If we determine that a customer is not creditworthy, we may not be required to deliver coal under the customer’s coal sales contract. If we are able to withhold shipments, we may decide to sell the customer’s coal on the spot market, which may be at prices lower than the contract price, or we may be unable to sell the coal at all.

Also, competition with other coal suppliers could force us to extend credit to customers on terms that could increase the risk of payment default.

In addition, we sell some of our coal to brokers who may resell our coal to end users, including utilities. These coal brokers may have only limited assets, making them less creditworthy than the end users. Under some of these arrangements, we have contractual privity only with the brokers and may not be able to pursue claims against the end users.

The bankruptcy or financial deterioration of any of our customers, whether an end user or a broker, could adversely affect our business, financial condition and/or results of operations.

A decline in demand for coal could adversely affect our ability to sell the coal we can produce and a decline in coal prices could render production from our coal reserves uneconomical.

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

• the domestic and foreign supply and demand for coal;

• the quantity and quality of coal available from competitors;

• a decline in prices under existing contracts where the pricing is tied to and adjusted periodically based on indices reflecting current market pricing;

• competition for production of electricity from non-coal sources, including the price and availability of alternative fuels;

• domestic air emission standards for coal-fueled power plants and the ability of coal-fueled power plants to meet these standards by installing scrubbers or other means;

• adverse weather, climate or other natural conditions, including natural disasters;

• the level of domestic and foreign taxes;

• domestic and foreign economic conditions, including economic slowdowns;

• legislative, regulatory and judicial developments, environmental regulatory changes or changes in energy policy and energy conservation measures that would adversely affect the coal industry, such as legislation limiting carbon emissions or providing for increased funding and incentives for alternative energy sources;

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• the proximity to, capacity of and cost of transportation and port facilities; and

• market price fluctuations for sulfur dioxide emission allowances.

Any adverse change in these factors could result in a decline in demand and lower prices for our coal.  In addition, the recent global economic downturn, coupled with the global financial and credit market disruptions, has had an impact on the coal industry generally and may continue to do so.  The demand for electricity, including demand from industrial customers, may remain at low levels or further decline if economic conditions remain weak.  If these trends continue, we may not be able to sell all of the coal we are capable of producing or sell our coal at prices comparable to recent years.  Recent low prices for natural gas, which is a substitute for coal-generated power, may also lead to continued decreased coal consumption by electricity-generating utilities.  A substantial or extended decline in the prices we receive under our coal supply contracts could adversely affect our business, financial condition and/or results of operations.

Any changes in consumption patterns by utilities away from the use of coal, such as changes resulting from low natural gas prices, could affect our ability to sell the coal we produce.

We compete with coal producers in Northern Appalachia and the Illinois Basin and in other coal producing regions of the United States.  The domestic demand for, and prices of, our coal primarily depend on coal consumption patterns of the domestic electric utility industry.  Thermal coal accounted for 100% of our coal sales volume for the year ended December 31, 2013. During this period, 74.3% of our thermal coal sales were to electric utilities for use primarily as fuel for domestic electricity consumption. The amount of coal consumed by the domestic electric utility industry is affected primarily by the overall demand for electricity, environmental and other governmental regulations, and the price and availability of competing fuels for power plants such as nuclear, natural gas and oil, as well as alternative sources of energy. In 2013, the EIA estimates that coal consumption in the electric power sector totaled 859.3 million tons, a historic low, due to low natural gas prices paid by the electric generators that led to a significant increase in the share of natural gas-fired power generation. The economic stability of these markets has a significant effect on the demand for coal and the level of competition in supplying these markets. A decline in price for other fuels, such as natural gas and oil, with which we compete could cause demand for coal to decrease and adversely affect the price of our coal. For example, low natural gas prices have led, in some instances, to decreased coal consumption by electricity-generating utilities. If alternative energy sources, such as nuclear, hydroelectric, wind or solar, become more cost-competitive on an overall basis, demand for coal could decrease and the price of coal could be materially and adversely affected. Further, legislation requiring, subsidizing or providing tax benefits for the use of alternative energy sources and fuels, or legislation providing financing or incentives to encourage continuing technological advances in this area, could further enable alternative energy sources to become more competitive with coal. During the last several years, the U.S. coal industry has experienced increased consolidation, which has contributed to the industry becoming more competitive.  Increased competition by coal producers or producers of alternate fuels could decrease the demand for, or pricing of, or both, for our coal, adversely affecting our business, financial condition and/or results of operations.

Unfavorable global or U.S. economic and market conditions could adversely impact the coal industry generally and us in particular.

Any global economic downturn, particularly with respect to the U.S. economy, and global financial and credit market disruptions, could have a negative impact on the coal industry generally and us in particular. For example, if the demand for electricity in our target markets decreases, this could lead to a decrease in coal consumption by customers. As a result, the coal inventory of our customers could increase leading to our customers curtailing future orders and causing a decrease in coal prices. Furthermore, because we typically seek to enter into long-term arrangements for the sale of a substantial portion of our coal, the average sales price we receive for our coal may lag behind any general economic recovery. Future economic downturns or further disruptions in the financial and credit markets could adversely affect our business, financial condition and/or results of operations.

An inability to acquire replacement coal reserves could adversely affect our ability to produce coal.

Our business, financial condition and results of operations depend substantially on obtaining coal reserves that have geological characteristics that enable them to be mined at competitive costs and to meet the coal quality needed by our customers.  Because we deplete our reserves as we mine coal, our future success and growth will depend, in part, upon our ability to acquire additional coal reserves that are economically recoverable.  If we fail to acquire or develop additional reserves, our existing reserves will eventually be depleted.  Replacement reserves may not be available when required or, if available, may not be capable of being mined at costs comparable to those characteristic of the depleting mines. Exhaustion of reserves at particular mines with certain valuable coal characteristics also may have an adverse effect on our operating results that is disproportionate to the percentage of overall production represented by such mines. Our ability to obtain other reserves could be limited by restrictions under our existing credit facilities or future debt agreements. Our inability to obtain reserves could adversely affect our business, financial condition and/or results of operations.

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There could be inaccuracies in the estimates of our coal reserves.

We base our coal reserve and non-reserve coal deposit estimates on engineering, economic and geological data assembled and analyzed by our staff, which data is periodically audited by an independent engineering firm. These estimates are also based on the expected costs of production, projected sale prices and assumptions concerning the ability to obtain mining permits. The estimates of coal reserves and non-reserve coal deposits, as to both quantity and quality, are periodically updated to reflect the production of coal from the reserves, updated geologic models and mining recovery data, recently acquired coal reserves and estimated costs of production and sales prices. There are numerous factors and assumptions inherent in estimating quantities and qualities of coal reserves, and non-reserve coal deposits and costs to mine recoverable reserves, including many factors beyond our control. Estimates of economically recoverable coal reserves necessarily depend upon a number of variable factors and assumptions, all of which may vary considerably from actual results. These factors and assumptions, many of which we cannot control, relate to:

• quality of the coal;

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

• the percentage of coal ultimately recoverable;

• the rate of royalties payable on the coal;

• the consequences of regulation, including the issuance of required permits, and taxes, including severance and excise taxes, and other payments to governmental agencies;

• assumptions concerning the timing for the development of reserves; and

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

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

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

Our right to mine some of our reserves may be adversely affected by actual or alleged defects in title or boundaries. In order to perfect leases or mining contracts on property where these defects exist, we may have to incur unanticipated costs. In other situations, we could even lose our right to mine on that property. In addition, from time to time the rights of third parties for competing uses of adjacent, overlying or underlying lands such as for oil and gas activity, coal bed methane production, pipelines, roads, easements and public facilities may affect our ability to operate as planned if our title is not superior or arrangements cannot be negotiated. Such defects in title could adversely affect our business, financial condition and/or results of operations.

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An inability to obtain and/or renew permits necessary for our operations could prevent us from mining certain of our coal reserves.

Numerous governmental permits and approvals are required for mining operations, and we can face delays in, challenges to, and difficulties in acquiring, maintaining or renewing necessary permits and approvals, including environmental permits. The permitting rules, and the interpretations of these rules, are complex, change frequently, and are often subject to discretionary interpretations by regulators, all of which may make compliance more difficult or impractical, and may possibly preclude the continuance of ongoing mining operations or the development of future mining operations. In addition, the public has certain statutory rights to comment upon and otherwise impact the permitting process, including through court intervention. Over the past few years, the length of time needed to bring a new surface mine into production has increased because of the increased time required to obtain necessary permits. The slowing pace at which permits are issued or renewed for new and existing mines has materially impacted production in Appalachia, but could also affect other regions in the future.

Section 402 National Pollutant Discharge Elimination System permits and Section 404 CWA permits are required to discharge wastewater and dredged or fill material into waters of the United States. Our surface coal mining operations typically require such permits to authorize activities such as the creation of sediment ponds and the reconstruction of streams and wetlands impacted by our mining operations. Although the CWA gives the EPA a limited oversight role in the Section 404 permitting program, the EPA has recently asserted its authorities more forcefully to question, delay, and prevent issuance of some Section 404 permits for surface coal mining in Appalachia. Currently, significant uncertainty exists regarding the obtaining of permits under the CWA for coal mining operations in Appalachia due to various initiatives launched by the EPA regarding these permits. An inability to obtain the necessary permits to conduct our mining operations or an inability to comply with the requirements of applicable permits could reduce our production and cash flows, which could adversely affect our business, financial condition and/or results of operations.

For more information, please read “Part I, Item 1. Business - Environmental, Safety and Other Regulatory Matters — Clean Water Act.”

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

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

These risks include:

• unfavorable geologic conditions, such as the thickness of the coal deposits and the amount of rock embedded in or overlying the coal deposit;

• inability to acquire or maintain necessary permits or mining or surface rights;

• changes in governmental regulation of the mining industry or the electric utility industry;

• adverse weather conditions and natural disasters;

• accidental mine water flooding;

• labor-related interruptions;

• transportation delays in barge, rail and truck systems due to weather-related problems, mechanical difficulties, strikes, bottlenecks, and other events;

• mining and processing equipment unavailability and failures and unexpected maintenance problems;

• our workforce could become unionized in the future; and

• accidents, including fire and explosions from methane.

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Any of these conditions may increase the cost of mining and delay or halt production at particular mines for varying lengths of time, which in turn could adversely affect our business, financial condition and/or results of operations.

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

Mining in Northern Appalachia and the Illinois Basin is more complex and involves more regulatory constraints than mining in other areas of the United States.

The geological characteristics of Northern Appalachian and Illinois Basin coal reserves, such as depth of overburden and coal seam thickness, make them complex and costly to mine. As mines become depleted, replacement reserves may not be available when required or, if available, may not be capable of being mined at costs comparable to those of the depleting mines. These factors could adversely affect our business, financial condition and/or results of operations.

We may experience unexpected increases in the costs for steel, diesel fuel, explosives and other materials necessary for our mining operations.

Our coal mining operations are affected by commodity prices. We use significant amounts of steel, diesel fuel, explosives and other materials in our mining operations. The prices of scrap steel, natural gas and coking coal consumed in the production of iron and steel could fluctuate significantly and unexpectedly. Additionally, a limited number of suppliers exist for explosives, and any of these suppliers may divert their products to other industries. Shortages in raw materials used in the manufacturing of explosives, which, in some cases, do not have ready substitutes, or the cancellation of supply contracts under which these raw materials are obtained, could increase the prices and limit the ability of us or our contractors to obtain these supplies. Future volatility in the prices and constraints on availability of steel, diesel fuel, explosives or other materials could adversely affect our business, financial condition and/or results of operations.

The assumptions underlying our reclamation and mine closure obligations could be materially inaccurate.

The Federal Surface Mining Control and Reclamation Act of 1977 and counterpart state laws and regulations establish operational, reclamation and closure standards for all aspects of surface mining, as well as most aspects of underground mining. Estimates of our total reclamation and mine closing liabilities are based upon permit requirements and our engineering expertise related to these requirements. While the estimate of our reclamation liability is reviewed regularly by our management, the estimate can change significantly if actual costs vary from assumptions or if governmental regulations change significantly. Such changes could adversely affect our business, financial condition and/or results of operations.

For more information, please read "Part II, Item 7 - Management's Discussion and Analysis of Financial Condition and Results of Operations—Critical Accounting Policies and Estimates—Reclamation and Mine Closure Costs."

Fluctuations in transportation costs or disruptions in transportation services could increase competition or impair our ability to deliver coal to our customers.

We depend upon barge, rail and truck systems to deliver coal to our customers.   Disruptions in transportation services due to weather-related problems, mechanical difficulties, strikes, lockouts, bottlenecks, and other events could impair our ability to deliver coal to our customers.  As we do not have long-term contracts with transportation providers to ensure consistent service, decreased performance levels over long periods of time could cause our customers to look to other sources for their coal needs.  In addition, increases in transportation costs, including the price of gasoline and diesel fuel, could make coal a less competitive source of energy when compared to alternative fuels or could make coal produced in one region of the United States less competitive than coal produced in other regions of the United States or abroad.

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It is possible that one or more states in which our coal is transported by truck may modify their laws to further limit truck weight limits.  Such legislation efforts could result in shipment delays and increased costs. If transportation services are disrupted, or if transportation costs increase significantly and we are unable to find alternative transportation providers at comparable prices, our business, financial condition and/or results of operations could be adversely affected.

Forward-purchase contracts related to our diesel fuel requirements may prevent us from benefiting from price decreases.

We enter into forward-purchase contract arrangements for a portion of our anticipated diesel fuel and explosive needs. Additionally, some of our expected diesel fuel requirements are protected, in varying amounts, by diesel fuel escalation provisions contained in coal supply contracts with some of our customers, that allow for a change in the price per coal ton sold. Price changes typically lag the changes in diesel fuel costs by one quarter. While our strategy provides us protection in the event of price increases to our diesel fuel, it may also prevent us from the benefits of price decreases. If prices for diesel fuel decreased significantly below our forward-purchase contracts, we would lose the benefit of any such decrease.

A shortage of skilled labor in the mining industry could reduce productivity and increase operating costs.

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

Our workforce could become unionized in the future.

Currently, none of our employees are represented under collective bargaining agreements.  However, all of our workforce may not remain union-free in the future.  If some or all of our workforce were to become unionized, it could adversely affect our productivity and labor costs and increase the risk of work stoppages, all of which could adversely affect our business, financial condition and/or results of operations.

The government extensively regulates mining operations, especially with respect to mine safety and health, which has the potential to significantly increase costs or limit our ability to produce coal.

Coal mining is subject to inherent risks to safety and health. As a result, the coal mining industry is subject to stringent safety and health standards. Fatal mining accidents have led to increased regulatory scrutiny of coal mining operations, particularly those underground. More stringent state and federal mine safety laws and regulations have included increased sanctions for non-compliance. Future workplace accidents are likely to result in more stringent enforcement and possibly the passage of new laws and regulations.

Within the last few years, the industry has seen enactment of the Federal Mine Improvement and New Emergency Response Act of 2006 (the “MINER Act”), subsequent additional legislation and regulation imposing significant new safety initiatives and the Dodd-Frank Act, which, among other things, imposes new mine safety reporting requirements. The MINER Act significantly amended the Federal Mine Safety and Health Act of 1977, imposing more extensive and stringent compliance standards, increasing criminal penalties, establishing a maximum civil penalty for non-compliance, and expanding the scope of federal oversight, inspection, and enforcement activities. Following the passage of the MINER Act, MSHA issued new or more stringent rules and policies on a variety of topics, including:

• mine safety equipment, training and emergency reporting requirements;

• substantially increased civil penalties for regulatory violations; and

• training and availability of mine rescue teams.

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Subsequently, various coal producing states, including West Virginia, Ohio and Kentucky, have enacted legislation addressing issues such as mine safety and accident reporting, increased civil and criminal penalties, and increased inspections and oversight. Other states may pass similar legislation in the future. Additional federal and state legislation that would further increase mine safety regulation, inspection and enforcement is being considered, particularly with respect to underground mining operations.

MSHA is also considering a new rule regarding respirable coal dust that, if promulgated, would lower the allowable average concentration of respirable dust, allow for single shift sampling to determine noncompliance and establish regulations for the use of Continuous Personal Dust Monitors, among other things. Although still in the comment stage, this proposed rule could require significant expenditures in order to comply.

Although we are unable to quantify the impact, implementing and complying with these new laws and regulations could adversely affect our business, financial condition and/or results of operations and could result in harsher sanctions in the event of any violations.

For more information, please read “Part I, Item 1 - Business—Environmental, Safety and Other Regulatory Matters.”

Federal legislation could result in higher healthcare costs.

In March 2010, the Patient Protection and Affordable Care Act (the “PPACA”) was enacted, impacting our costs of providing healthcare benefits to our eligible active employees, with both short-term and long-term implications. In the short term, our healthcare costs could increase due to, among other things, an increase in the maximum age for covered dependents to receive benefits, changes to benefits for occupational disease related illnesses, the elimination of lifetime dollar limits per covered individual and restrictions on annual dollar limits per covered individual. In the long term, our healthcare costs could increase for these same reasons, as well as due to an excise tax on “high cost” plans, among other things. Implementation of this legislation is expected to extend through 2018.

Beginning in 2018, the PPACA will impose a 40% excise tax on employers to the extent that the value of their healthcare plan coverage exceeds certain dollar thresholds. We anticipate that certain governmental agencies will provide additional regulations or interpretations concerning the application of this excise tax. We will continue to evaluate the impact of the PPACA, including any new regulations or interpretations, in future periods.

Any increase in cost, as a result of legislation or otherwise, could adversely affect our business, financial condition and/or results of operations.

Federal and state laws require surety bonds to secure obligations to reclaim mined property, and an inability to acquire or failure to maintain, obtain or renew these surety bonds could have an adverse effect on our ability to produce coal.

We are required under federal and state laws to place and maintain bonds to secure our obligations to return property to its approximate original state after the property has been mined (often referred to as "reclamation") and to satisfy other obligations, such as coal leases and the performance of specific tasks. Federal and state governments could increase bonding requirements in the future and we may have difficulty procuring or maintaining our surety bonds. Additionally, our bond issuers may demand higher fees, additional collateral, including supporting letters of credit or posting cash collateral or other terms less favorable to us upon those renewals. The failure to maintain or the inability to acquire sufficient surety bonds, as required by state and federal laws, could subject us to fines and penalties as well as the loss of our mining permits.

In the future, it is possible that we may have difficulty obtaining or maintaining our surety bonds. Due to current economic conditions and the volatility of the financial markets, surety bond providers may be less willing to provide us with surety bonds or maintain existing surety bonds or may demand terms that are less favorable to us than the terms we currently receive. We may also have difficulty satisfying the liquidity requirements under our existing surety bond contracts.

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Our inability to obtain or maintain the required surety bonds could adversely affect our business, financial condition and/or results of operations.

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

The coal mining industry is subject to numerous and extensive federal, state and local environmental laws and regulations, including laws and regulations pertaining to permitting and licensing requirements, air quality standards, plant and wildlife protection, reclamation and restoration of mining properties, the discharge of materials into the environment, the storage, treatment and disposal of wastes, protection of wetlands, surface subsidence from underground mining, and the effects that mining has on groundwater quality and availability. The costs, liabilities and requirements associated with these laws and regulations are significant, time-consuming and may delay commencement or continuation of our operations.

The possibility exists that new laws or regulations (or new judicial interpretations or enforcement of existing laws and regulations) could materially affect our mining operations and our business, financial condition and/or results of operations, either through direct impacts such as those regulating our existing mining operations, or indirect impacts such as those that discourage or limit our customers' use of coal. Although we believe that we are in substantial compliance with existing laws and regulations, we may, in the future, experience violations that would subject us to administrative, civil and criminal penalties and a range of other possible sanctions. As a result, the consequences for any noncompliance may become more significant in the future.

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

Any of these conditions could adversely affect our business, financial condition and/or results of operations.

Federal or state regulatory agencies have the authority to order certain of our mines to be temporarily or permanently closed under certain circumstances.

Federal or state regulatory agencies have the authority to temporarily or permanently close a mine following significant health and safety incidents, such as a fatality. In the event that these agencies order the closing of our mines, our coal sales contracts generally permit us to issue force majeure notices which suspend our obligations to deliver coal under these contracts. However, our customers may challenge our issuances of force majeure notices. If these challenges are successful, we may have to purchase coal from third-party sources, if it is available, and potentially at prices higher than our cost to produce coal, to fulfill these obligations, and negotiate settlements with customers, which may include price and quantity reductions, the extension of time for delivery, or contract termination. Additionally, we may be required to incur capital expenditures to re-open the mine. These actions could adversely affect our business, financial condition and/or results of operations.

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

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

In the wake of the Supreme Court's April 2007 decision in Massachusetts, et al. v. EPA, which held that GHGs fall under the definition of “air pollutant” in the CAA, in December 2009 the EPA issued a final rule declaring that six GHGs, including carbon dioxide and methane, “endanger both the public health and the public welfare of current and future generations.” The issuance of this “endangerment finding” allows the EPA to begin regulating GHG emissions under existing provisions of the CAA.  There are many regulatory approaches currently in effect or being considered to address GHGs, including U.S. treaties, new federal or state legislation that may impose a carbon emissions tax, or establish a cap-and-trade program and regulation by the EPA.

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The permitting of new coal-fired power plants has also been contested by state regulators and environmental organizations for concerns related to GHG emissions from the new plants.  In addition, several permits issued to new coal-fired power plants without limits on GHG emissions have been appealed to EPA’s Environmental Appeals Board.  As state permitting authorities continue to consider GHG control as part of major source permitting Best Available Control Technology (“BACT”) requirements, costs associated with new facility permitting and use of coal could increase substantially.  A growing concern is the possibility that BACT will be determined to be the use of an alternative fuel to coal.

As a result of these current and proposed laws, regulations and trends, electricity generators may elect to switch to other fuels that generate less GHG emissions, possibly further reducing demand for our coal, which could adversely affect our business, financial condition and/or results of operations.

For more information, please read “Part I, Item 1 - Business — Environmental, Safety and Other Regulatory Matters — Climate Change.”

Existing and future laws and regulations regulating the emission of sulfur dioxide and other compounds could affect coal consumers and as a result reduce demand for our coal.

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

For more information, please read “Part I, Item 1 - Business — Environmental, Safety and Other Regulatory Matters — Air Emissions.”

The success of our business is dependent on key personnel.

We depend on the services of our senior management team and other key personnel. We may not be able to locate or employ on acceptable terms qualified replacements for senior management or other key employees if their services were no longer available. The loss of the services of any member of senior management or key employee could adversely affect our business, financial condition and/or results of operations.

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

In January 2007, we entered into a joint venture, Harrison Resources, with CONSOL. Pursuant to its operating agreement, all members of Harrison Resources must approve cash distributions, other than tax distributions, to its members. Prior to 2012, cash distributions were approved and received on a quarterly basis. In 2012 and 2013, the members of Harrison Resources did not approve any cash distributions, as it was necessary to reserve cash to pay coal reserve acquisition costs. Distributions are not anticipated in 2014 as it is expected that it will be necessary to continue to reserve cash for similar purposes. For that reason and otherwise, there can be no assurance that we will receive cash distributions from Harrison Resources in the future.

CONSOL controls the vast majority of the 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 cannot assure you that Harrison Resources could acquire those or other reserves on acceptable terms. As a result, the growth of, and therefore our ability to receive future distributions from, Harrison Resources may be limited, which could adversely affect our business, financial condition and/or results of operations.

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We are subject to various legal proceedings.

We are party to a number of legal proceedings incident to our normal business activities. There is the potential that an individual matter or the aggregation of multiple matters could adversely affect our business, financial condition and/or results of operations.

Risks Inherent in an Investment in Us

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

Fiduciary duties owed to our unitholders by our general partner are prescribed by law and the partnership agreement. The Delaware Revised Uniform Limited Partnership Act (the “Delaware Act”) provides that Delaware limited partnerships may, in their partnership agreements, restrict the fiduciary duties owed by the general partner to limited partners and the partnership. Our partnership agreement contains such provisions. For example, our partnership agreement:

• limits the liability and reduces the fiduciary duties of our general partner, while also restricting the remedies available to our unitholders for actions that, without these limitations, might constitute breaches of fiduciary duty. As a result of purchasing common units, our unitholders consent to some actions and conflicts of interest that might otherwise constitute a breach of fiduciary or other duties under applicable state law;

• permits our general partner to make a number of decisions in its individual capacity, as opposed to in its capacity as our general partner. This entitles our general partner to consider only the interests and factors that it desires, and it has no duty or obligation to give any consideration to any interest of, or factors affecting, us, our affiliates or any limited partner. Examples include the exercise of its limited call right, its voting rights with respect to the units it owns, its registration rights and its determination whether or not to consent to any merger or consolidation of the partnership;

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

• generally provides that affiliated transactions and resolutions of conflicts of interest not approved by the audit committee of the board of directors of our general partner acting as a conflicts committee, and not involving a vote of our unitholders, must be on terms no less favorable to us than those generally being provided to or available from unrelated third parties or be “fair and reasonable” to us and that, in determining whether a transaction or resolution is “fair and reasonable,” our general partner may consider the totality of the relationships between the parties involved, including other transactions that may be particularly advantageous or beneficial to us; and

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

By purchasing a common unit, a common unitholder will become bound by the provisions of our partnership agreement, including the provisions described above.

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

C&T Coal owns an 18.0% limited partner interest in us, AIM Oxford owns a 35.3% limited partner interest in us, and C&T Coal and AIM Oxford own substantially all of and control our general partner and its 2.0% general partner interest in us. Although our general partner has certain fiduciary duties to manage us in a manner beneficial to us and our unitholders, the executive officers and directors of our general partner have a fiduciary duty to manage our general partner in a manner beneficial to its owners. Furthermore, since certain executive officers and directors of our general partner are executive officers or directors of affiliates of our general partner, conflicts of interest may arise between C&T Coal and AIM Oxford and their affiliates, including our general partner, on the one hand, and us and our unitholders, on the other hand. As a result of these conflicts, our general partner may favor its own interests and the interests of its affiliates over the interests of our unitholders. The risk to our unitholders due to such conflicts may arise because of the following factors, among others:

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

• neither our partnership agreement nor any other agreement requires owners of our general partner to pursue a business strategy that favors us. Executive officers and directors of our general partner’s owners have a fiduciary duty to make these decisions in the best interest of their owners, which may be contrary to our interests;

• our general partner determines the amount and timing of asset purchases and sales, capital expenditures, borrowings and issuances of additional partnership securities and reserves, each of which can affect our financial condition;

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

• our partnership agreement does not restrict our general partner from causing us to pay it or its affiliates for any services rendered on terms that are fair and reasonable to us or entering into additional contractual arrangements with any of these entities on our behalf;

• our general partner intends to limit its liability regarding our contractual and other obligations;

• our general partner may exercise its limited right to call and purchase common units if it and its affiliates own more than 80% of the common units which could cause unitholders to sell units at a time and price that may not be desirable;

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

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

In addition, AIM currently holds substantial interests in other companies in the energy and natural resource sectors. Our partnership agreement provides that our general partner will be restricted from engaging in any business activities other than acting as our general partner and those activities incidental to its ownership interest in us. However, AIM and AIM Oxford are not prohibited from engaging in other businesses or activities, including those that might be in direct competition with us. As a result, they could potentially compete with us for acquisition opportunities and for new business or extensions of the existing services provided by us.

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

For more information, please read “— Our partnership agreement limits our general partner’s fiduciary duties to our unitholders and restricts the remedies available to our unitholders for actions taken by our general partner that might otherwise constitute breaches of fiduciary duties.”

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Our unitholders have limited voting rights, are not entitled to elect our general partner or its directors and have limited ability to remove our general partner without its consent.

Unlike the holders of common stock in a corporation, our unitholders have only limited voting rights on matters affecting our business and, therefore, limited ability to influence management’s decisions regarding our business. Our unitholders have no right to elect our general partner or its board of directors on an annual or other continuing basis. The board of directors of our general partner is chosen entirely by its members and not by our unitholders. Furthermore, if our unitholders are dissatisfied with the performance of our general partner, they have limited ability to remove our general partner.

Our unitholders are unable to remove our general partner without its consent because affiliates of our general partner own sufficient units to be able to prevent removal of our general partner. The vote of the holders of at least 80% of all outstanding common units and subordinated units voting together as a single class is required to remove our general partner. Affiliates of our general partner own 53.3% of our common units and subordinated units. Also, if our general partner is removed without cause during the subordination period and units held by our general partner and its affiliates are not voted in favor of that removal, all remaining subordinated units will automatically be converted into common units and any existing arrearages on the common units will be extinguished. A removal of our general partner under these circumstances would adversely affect the common units by prematurely eliminating their distribution and liquidation preference over the subordinated units, which would otherwise have continued until we had met certain distribution and performance tests.

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

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

Our general partner may transfer its general partner interest in us to a third party in a merger or in a sale of all or substantially all of its assets without the consent of our unitholders. Furthermore, there is no restriction in our partnership agreement on the ability of the members of our general partner to transfer their respective membership interests in our general partner to a third party. The new members of our general partner would then be in a position to replace the board of directors and executive officers of our general partner with their own choices and to control the decisions and actions of the board of directors and executive officers of our general partner.

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

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

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

At any time that our general partner and its affiliates own more than 80.0% of the common units, our general partner will have the right, but not the obligation, which it may assign to any of its affiliates or to us, to acquire all, but not less than all, of the common units held by unaffiliated persons at a price not less than the then-current market price.  As a result, our unitholders may be required to sell their common units at an undesirable time or price and may not receive any return on their investment.  Our unitholders may also incur a tax liability upon a sale of their common units.  Our general partner is not obligated to obtain a fairness opinion regarding the value of the common units to be repurchased by it upon exercise of the limited call right.  There is no restriction in our partnership agreement that prevents our general partner from issuing additional common units and exercising its limited call right.  If our general partner exercised its limited call right, the effect would be to take us private and, if the common units were subsequently deregistered, we would no longer be subject to the reporting requirements of the Exchange Act.

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We may issue additional units without unitholder approval.

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

• our unitholders’ proportionate ownership interest in us will decrease;

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

• the risk that a shortfall in the payment of the minimum quarterly distribution will be borne by our common unitholders will increase, because a lower percentage of total outstanding units will be subordinated units;

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

• the market price of the common units may decline.

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

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

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

The market price of our common units could be impacted by sales of substantial amounts of our common units in the public markets, including sales by our existing unitholders.

A unitholder may sell some or all of our common units that it owns or it may distribute our common units to the holders of its equity interests and those holders may dispose of some or all of these units. The sale or disposition of a substantial number of our common units in the public markets could have a material adverse effect on the price of our common units or could impair our ability to obtain capital through an offering of equity securities. We do not know whether any such sales would be made in the public market or in private placements, nor do we know what impact such potential or actual sales would have on our unit price in the future.

An increase in interest rates may cause the market price of our common units to decline.

Like all equity investments, an investment in our common units is subject to certain risks. In exchange for accepting these risks, investors may expect to receive a higher rate of return than would otherwise be obtainable from lower-risk investments. Accordingly, as interest rates rise, the ability of investors to obtain higher risk-adjusted rates of return by purchasing government-backed debt securities may cause a corresponding decline in demand for riskier investments generally, including yield-based equity investments such as publicly-traded limited partnership interests. Reduced demand for our common units resulting from investors seeking other more favorable investment opportunities may cause the trading price of our common units to decline.

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Cost reimbursements may be due to our general partner and its affiliates.

We will reimburse our general partner and its affiliates for all expenses they incur on our behalf, which will be determined by our general partner in its sole discretion in accordance with the terms of our partnership agreement. In determining the costs and expenses allocable to us, our general partner is subject to its fiduciary duty, as modified by our partnership agreement, to the limited partners, which requires it to act in good faith. These expenses include all costs incurred by our general partner and its affiliates in managing and operating us. We are managed and operated by executive officers and directors of our general partner. The reimbursement of expenses and payment of fees, if any, to our general partner and its affiliates will reduce our cash.

Our unitholders may have liability to repay distributions.

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

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

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

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

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Tax Risks

Our tax treatment depends on our status as a partnership for federal income tax purposes.

The anticipated after-tax economic benefit of an investment in our common units depends largely on our being treated as a partnership for federal income tax purposes. We have not requested, and do not plan to request, a ruling from the IRS on this or any other tax matter affecting us.

Despite the fact that we are a limited partnership under Delaware law, it is possible in certain circumstances for a partnership such as ours to be treated as a corporation for federal income tax purposes. A change in our business or a change in current law could cause us to be treated as a corporation for federal income tax purposes or otherwise subject us to taxation as an entity.

If we were treated as a corporation for federal income tax purposes, we would pay federal income tax on our taxable income at the corporate tax rate, which is currently a maximum of 35.0%, and would likely pay state and local income tax at varying rates. Distributions would generally be taxed again as corporate dividends (to the extent of our current and accumulated earnings and profits), and no income, gains, losses, deductions, or credits would flow through to our unitholders. Because a tax would be imposed upon us as a corporation, our financial condition would be adversely affected. Therefore, if we were treated as a corporation for federal income tax purposes there could be a material reduction in the anticipated cash flow and after-tax return to our unitholders, likely causing a substantial reduction in the value of our common units.

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

We could be subjected to additional entity-level taxation by individual states.

Changes in current state law may subject us to additional entity-level taxation by individual states.  Because of widespread state budget deficits and other reasons, several states are evaluating ways to subject partnerships to entity-level taxation through the imposition of state income, franchise and other forms of taxation.  Imposition of any such taxes could adversely affect our financial condition.

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

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

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

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

The present U.S. federal income tax treatment of publicly traded partnerships, including us, or an investment in our common units may be modified by administrative, legislative or judicial interpretation at any time. In the past, members of the U.S. Congress have considered substantive changes to the existing U.S. federal income tax laws that would have affected the tax treatment of certain publicly traded partnerships. Any modification to the U.S. federal income tax laws or interpretations thereof may or may not be applied retroactively. Although we are unable to predict whether any of these changes or any other proposals will ultimately be enacted, any changes could negatively impact the value of an investment in our common units.

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

Among the changes contained in President Obama’s most recent budget proposal (the “Budget Proposal”) is the elimination of certain key U.S. federal income tax preferences relating to coal exploration and development. The Budget Proposal would have: (i) eliminated current deductions, the 60-month amortization period and the 10-year amortization period for exploration and development costs relating to coal and other hard mineral fossil fuels, (ii) repealed the percentage depletion allowance with respect to coal properties, (iii) repealed capital gains treatment of coal and lignite royalties and (iv) excluded from the definition of domestic production gross receipts all gross receipts derived from the production of coal and other hard mineral fossil fuels. The passage of any legislation effecting changes similar to those in the Budget Proposal in U.S. federal income tax laws could eliminate certain tax deductions that are currently available with respect to coal exploration and development, and any such change could increase the taxable income allocable to our unitholders and negatively impact the value of an investment in our common units.

If the IRS contests the federal income tax positions we take, we could incur costs for the contest and the market for our common units could be affected.

We have not requested a ruling from the IRS with respect to our treatment as a partnership for federal income tax purposes or any other matter affecting us. The IRS may adopt positions that differ from the positions we take, and the IRS’s positions may ultimately be sustained. It may be necessary to resort to administrative or court proceedings to sustain some or all of the positions we take and such positions may not ultimately be sustained. A court may not agree with some or all of the positions we take. Any contest with the IRS, and the outcome of any IRS contest, may have a materially adverse impact on the market for our common units and the price at which they trade. In addition, our costs of any contest with the IRS will be borne indirectly by our unitholders and our general partner because the costs could adversely affect our financial condition.

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

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

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

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

We treat each purchaser of our common units as having the same tax benefits without regard to the actual common units purchased, and the IRS could challenge this treatment.

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

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

We prorate our items of income, gain, loss and deduction for U.S. federal income tax purposes between transferors and transferees of our units each month based upon the ownership of our units on the first day of each month, instead of on the basis of the date a particular unit is transferred. The use of this proration method may not be permitted under existing Treasury Regulations. Recently, the U.S. Treasury Department issued proposed Treasury Regulations that provide a safe harbor pursuant to which publicly traded partnerships may use a similar monthly simplifying convention to allocate tax items. Nonetheless, the proposed regulations do not specifically authorize the use of the proration method we have adopted. If the IRS were to challenge this method or new Treasury Regulations were issued, we may be required to change the allocation of items of income, gain, loss and deduction among our unitholders.

A unitholder whose common units are loaned to a “short seller” to effect a short sale of common units may be considered as having disposed of those common units.

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

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

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

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

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

We will be considered to have technically terminated our partnership for federal income tax purposes if there is a sale or exchange of 50% or more of the total interests in our capital and profits within a twelve-month period. For purposes of determining whether the 50% threshold has been met, multiple sales of the same interest will be counted only once. Our technical termination would, among other things, result in the closing of our taxable year for all unitholders, which would result in us filing two tax returns (and our unitholders could receive two Schedules K-1 if relief was not available, as described below) for one fiscal year and could result in a deferral of depreciation deductions allowable in computing our taxable income. In the case of a unitholder reporting on a taxable year other than a fiscal year ending December 31, the closing of our taxable year may also result in more than twelve months of our taxable income or loss being includable in our unitholders’ taxable income for the year of termination. Our termination currently would not affect our classification as a partnership for federal income tax purposes, but instead we would be treated as a new partnership for tax purposes. If treated as a new partnership, we must make new tax elections and could be subject to penalties if we are unable to determine that a termination occurred. The IRS has recently announced a publicly traded partnership technical termination relief program whereby, if a publicly traded partnership that technically terminated requests publicly traded partnership technical termination relief and such relief is granted by the IRS, among other things, the partnership will only have to provide one Schedule K-1 to unitholders for the year notwithstanding two partnership tax years.

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

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

Item 1B.           Unresolved Staff Comments

None.

Item 2.              Properties

Mining Operations

See “Part I, Item 1 - Business - Operations” for specific information about our mining operations.

Coal Reserves

We base our coal reserve estimates on engineering, economic and geological data assembled and analyzed by our staff. These estimates are also based on the expected cost of production and projected sale prices and assumptions concerning permitability. The estimates of coal reserves as to both quantity and quality are periodically updated to reflect the production of coal from the reserves, updated geologic models and mining recovery data, coal reserves recently acquired and estimated costs of production and sales prices. Changes in mining methods may increase or decrease the recovery basis for a coal seam as will plant processing efficiency tests.

Periodically, we retain outside experts to independently verify our coal reserve and our non-reserve coal deposit estimates. At December 31, 2013, an audit review of our coal reserves was completed by John T. Boyd Company, an independent mining and geological consulting firm. We intend to continue to periodically retain outside experts to assist management with the verification of our estimates of our coal reserves and non-reserve coal deposits going forward.

As of December 31, 2013, we owned 13.7% of our coal reserves and leased 86.3% of our coal reserves from various third parties. As of December 31, 2013, we controlled an estimated 81.6 million tons of proven and probable reserves, including 24.3 million tons of underground reserves we sublease to a third party.

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The following table provides information as of December 31, 2013 on the location of our operations and the amount and ownership of our coal reserves:

	Total Proven and Probable Coal Reserves
Mining Complex	Total			Owned			Leased
	(tons in thousands)
Surface Mining Operations:
Northern Appalachia (principally Ohio)
Cadiz		6,943			3,769			3,174
Tuscarawas		7,371			185			7,186
Plainfield		2,771			737			2,034
Belmont		11,923			1,054			10,869
New Lexington		7,314			944			6,370
Harrison (1)		2,984			2,984			-
Noble		1,627			-			1,627
Total Northern Appalachia		40,933			9,673			31,260
Illinois Basin (Kentucky)
Muhlenberg		16,296			1,473			14,823
Total Illinois Basin		16,296			1,473			14,823
Total Surface Mining Operations		57,229			11,146			46,083
Underground Coal Reserves:
Tusky		24,331			-			24,331
Total Underground Coal Reserves		24,331			-			24,331
Total		81,560			11,146			70,414
Percentage of Total		100.0	%		13.7	%		86.3	%

(1) The Harrison mining complex is owned by Harrison Resources. We own 51% of Harrison Resources and CONSOL owns the remaining 49% of Harrison Resources through one of its subsidiaries. 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, proven and probable coal reserves attributable to the Harrison mining complex are presented on a gross basis assuming we owned 100% of Harrison Resources.

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The following table provides information on particular characteristics of our coal reserves as of December 31, 2013:

	As Received Basis(1)
							Lbs. of		Proven and Probable Coal Reserves
							SO2/mm		Sulfur Content(1)
Mining Complex	Btu/lb.		% Ash		% Sulfur		Btu		<2%		2-4%	>4%		Total
									(tons in thousands)
Surface Mining Operations:
Northern Appalachia (principally Ohio)
Cadiz		11,370		12.9		3.3		5.9		663	4,213		2,067		6,943
Tuscarawas		11,825		10.3		4.2		7.1		940	1,643		4,788		7,371
Plainfield		11,836		9.3		4.4		7.5		--	765		2,006		2,771
Belmont		11,820		12.6		4.2		7.0		--	3,885		8,038		11,923
New Lexington		11,105		13.0		4.1		7.4		--	2,621		4,693		7,314
Harrison(2)		11,287		12.8		1.9		3.4		1,959	1,025		--		2,984
Noble		11,242		11.1		4.9		8.7		--	--		1,627		1,627
Illinois Basin (Kentucky)
Muhlenberg		11,314		11.3		3.6		6.4		--	15,884		412		16,296
Underground Coal Reserves:
Tusky		12,900		5.3		2.1		3.2		3,768	20,563		--		24,331

______________

(1) As received represents an analysis of a sample as received at a laboratory operated by a third party.

(2) The Harrison mining complex is owned by Harrison Resources. We own 51% of Harrison Resources and CONSOL owns the remaining 49% of Harrison Resources through one of its subsidiaries. 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, proven and probable coal reserves attributable to the Harrison mining complex are presented on a gross basis assuming we owned 100% of Harrison Resources.

Office Facilities

We lease office space in Columbus, Ohio for our executives and related administrative support staff. Our lease at 41 South High Street, Columbus, Ohio expires in February 2015. In addition, we own buildings, primarily for our administrative support and operational support staffs, located at 544 Chestnut Street, Coshocton, Ohio and 40580 Cadiz-Piedmont Road, Cadiz, Ohio, respectively.

Item 3.             Legal Proceedings

We may, from time to time, be involved in various legal proceedings and claims arising out of our operations in the normal course of business. While many of these matters involve inherent uncertainty, we do not believe that we are a party to any legal proceedings or claims that will have a material adverse impact on our business, financial condition or results of operations.

Item 4.             MINE SAFETY DISCLOSURES

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 for the year ended December 31, 2013 is included as Exhibit 95 to this Annual Report on Form 10-K.

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PART II

Item 5.             Market for Registrant’s Common Equity, Related Unitholder Matters and Issuer Purchases of Equity Securities

Our common units began trading on the NYSE under the symbol "OXF" on July 14, 2010. On February 28, 2014, the closing market price for our common units was $1.18 per unit. The following table sets forth the range of the daily high and low sales prices and cash distribution per common unit and the cash distribution per subordinated unit for the periods indicated:

Period	High Price		Low Price		Common Unit Distribution(1)		Subordinated Unit Distribution(1)
First Quarter 2012	$	17.93	$	6.75	$	0.4375	$	0.4375
Second Quarter 2012	$	9.74	$	6.50	$	0.4375	$	0.1000
Third Quarter 2012	$	9.98	$	7.29	$	0.2000	$	-
Fourth Quarter 2012	$	11.75	$	4.25	$	-	$	-
First Quarter 2013	$	6.11	$	2.11	$	-	$	-
Second Quarter 2013	$	3.45	$	2.10	$	-	$	-
Third Quarter 2013	$	2.86	$	1.90	$	-	$	-
Fourth Quarter 2013	$	1.99	$	1.08	$	-	$	-

(1) Represents cash distributions attributable to the quarter. Cash distributions declared in respect of a calendar quarter are paid in the following calendar quarter.

As of February 28, 2014, we had outstanding 10,589,149 common units, 10,280,380 subordinated units and 423,494 general partner units. We also had outstanding warrants to purchase an aggregate of 1,955,666 common units and 1,814,185 subordinated units at an exercise price of $0.01 per unit. There were approximately 32 record holders of common units on December 31, 2013. The number does not include unitholders whose units are held in trust by other entities. The actual number of unitholders is greater than the number of holders of record. All of the subordinated units and general partner units, for which there is no established public trading market, are held by affiliates of our general partner. The affiliates of our general partner are entitled to receive quarterly distributions on the subordinated units only after sufficient distributions (including any arrearage amounts) have been made on the common units.

Cash Distribution Policy

Our partnership agreement requires that we distribute all of our available cash quarterly. Under our partnership agreement, available cash is generally defined to mean, for each quarter, cash generated from our business in excess of the amount of cash reserves established by our general partner to provide for the conduct of our business, to comply with applicable law to make payments related to any of our debt instruments or other agreements, or to provide for future distributions to our unitholders for any one or more of the next four quarters. Our available cash may also include, if our general partner so determines, all or any portion of the cash on hand on the date of determination of available cash for the quarter resulting from working capital borrowings made subsequent to the end of such quarter.

Our partnership agreement provides that, during a period of time referred to as the “subordination period,” the common units will have the right to receive distributions of available cash from operating surplus each quarter in an amount equal to $0.4375 per common unit, which amount is defined in our partnership agreement as the “minimum quarterly distribution,” plus any arrearages in the payment of the minimum quarterly distribution on the common units from prior quarters, before any distributions of available cash from operating surplus may be made on the subordinated units. No arrearages are payable on the subordinated units.

The subordination period will end on the first business day after we have earned and paid from operating surplus generated in the applicable period at least (i) $1.75 (the minimum quarterly distribution on an annualized basis) on each outstanding common and subordinated unit and the corresponding distribution on our general partner units for each of three consecutive, non-overlapping four quarter periods ending on or after September 30, 2013 or (ii) $0.65625 per quarter (150.0% of the minimum quarterly distribution, which is $2.625 on an annualized basis) on each outstanding common and subordinated unit and the corresponding distributions on our general partner units for any four quarter period ending on or after September 30, 2012. In addition, the subordination period will end upon the removal of our general partner other than for cause if the units held by our general partner and its affiliates are not voted in favor of such removal, and in that case each outstanding subordinated unit will convert into one common unit and any existing arrearages in payment of the minimum quarterly distribution on the common units will be extinguished. All of our subordinated units are held by AIM Oxford and C&T Coal.

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Our general partner is entitled to 2.0% of all quarterly distributions that we make prior to our liquidation. This general partner interest is represented by 423,494 general partner units. Our general partner also currently holds incentive distribution rights that entitle it to receive increasing percentages, up to a maximum of 50.0%, of the cash we distribute from operating surplus in excess of $0.5031 per unit per quarter. The maximum distribution of 50.0% includes distributions paid to our general partner on its 2.0% general partner interest and assumes that our general partner maintains its general partner interest at 2.0%. The maximum distribution of 50.0% does not include any distributions that our general partner may receive on common units or subordinated units that it owns. We did not pay our general partner any amounts with respect to its incentive distribution rights in connection with distributions for 2013.

In January 2013 we determined to suspend the cash distributions on both our common and subordinated units, based upon continued weakness in the coal markets. Under our partnership agreement, arrearage amounts resulting from suspension of the common units distribution accumulate. Arrearage amounts resulting from suspension of the subordinated units distribution do not accumulate. In the future if and as distributions are made for any quarter, the first priority is to pay the then minimum quarterly distribution to common unitholders. Any additional distribution amounts paid at that time are then paid to common unitholders until their previously unpaid accumulated arrearage amounts have been paid in full. At December 31, 2013, the accumulated arrearage amount totaled $25.3 million.

In June 2013, we closed on $175 million of credit facilities that replaced our previous term loan and revolving credit facility, which credit facilities have customary financial and other covenants, and also preclude us from making unitholder distributions during their terms. See “Item 7 - Management’s Discussion and Analysis of Financial Condition and Results of Operation —Recent Developments — Credit Facilities.”

Unregistered Sales of Equity Securities

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

During the years ended December 31, 2012, 2011, and 2010 we received contributions of approximately $12,554, $28,535, and $22,237, respectively, from our general partner as consideration for the issuance to our general partner of 1,450, 1,411, and 1,026 general partner units, respectively. These transactions were exempt from registration pursuant to Section 4(2) of the Securities Act of 1933, as amended.

In June 2013, in connection with the second lien credit facility, certain lenders and lender affiliates received warrants entitling them to purchase an aggregate of 1,955,666 common units and 1,814,185 subordinated units at $0.01 per unit. The warrants participate in distributions whether or not exercised. This transaction was exempt from registration pursuant to Section 4(2) of the Securities Act of 1933, as amended.

Issuer Purchases of Equity Securities.

During 2013, we did not make any purchases of our common units and no such purchases were made on our behalf.

Securities Authorized for Issuance Under Equity Compensation Plan

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

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Item 6.     Selected Financial and Operating Data

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

SELECTED FINANCIAL AND OPERATING DATA

	Oxford Resource Partners, LP Year Ended December 31,
	2013			2012			2011			2010			2009
				(in thousands, except per ton amounts)
STATEMENT OF OPERATIONS DATA:
REVENUES:
Coal sales	$	336,201		$	364,928		$	391,046		$	350,057		$	286,661
Other revenue		10,566			8,599			9,331			8,369			7,183
Total revenues		346,767			373,527			400,377			358,426			293,844
COSTS AND EXPENSES:
Cost of coal sales:
Produced coal		268,130			288,782			316,574			264,350			200,766
Purchased coal		22,297			23,685			13,480			22,024			19,487
Total cost of coal sales (excluding depreciation, depletion and amortization)		290,427			312,467			330,054			286,374			220,253
Cost of other revenue		1,619			1,195			1,799			2,380			1,245
Depreciation, depletion and amortization		48,081			51,170			51,905			42,329			25,902
Selling, general and administrative expenses		17,297			15,629			13,739			17,257			13,242
Impairment and restructuring expenses		1,761			15,650			-			-			-
(Gain) loss on disposal of assets		(6,488	)		(8,021	)		1,352			1,228			1,177
Total costs and expenses		352,697			388,090			398,849			349,568			261,819
(LOSS) INCOME FROM OPERATIONS		(5,930	)		(14,563	)		1,528			8,858			32,025
Interest income		4			10			13			12			35
Interest expense		(21,054	)		(11,500	)		(9,870	)		(9,511	)		(6,484	)
Change in fair value of warrants		3,280			-			-			-			-
Gain on purchase of business (1)		-			-			-			-			3,823
NET (LOSS) INCOME		(23,700	)		(26,053	)		(8,329	)		(641	)		29,399
Net income attributable to noncontrolling interest		(1,225	)		(755	)		(4,748	)		(6,710	)		(5,895	)
Net (loss) income attributable to Oxford
Resource Partners, LP unitholders		(24,925	)		(26,808	)		(13,077	)		(7,351	)		23,504
Net (loss) income allocated to general partner		(497	)		(535	)		(261	)		(147	)		467
Net (loss) income allocated to limited partners	$	(24,428	)	$	(26,273	)	$	(12,816	)	$	(7,204	)	$	23,037
Net (loss) income per limited partner unit:
Basic	$	(1.07	)	$	(1.27	)	$	(0.62	)	$	(0.45	)	$	2.09
Diluted	$	(1.07	)	$	(1.27	)	$	(0.62	)	$	(0.45	)	$	2.08
Weighted average number of limited partner units outstanding:
Basic		22,776,481			20,711,952			20,641,127			15,887,977			11,033,840
Diluted		22,776,481			20,711,952			20,641,127			15,887,977			11,083,170
Distributions paid per unit:
Limited partners:
Common	$	-		$	1.5125		$	1.7500		$	0.5826	(2)	N/A
Subordinated	$	-		$	0.6375		$	1.7500		$	0.5826	(2)	$	1.2000
General partner	$	-		$	1.0750		$	1.7500		$	0.5826	(2)	$	1.2000

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SELECTED FINANCIAL AND OPERATING DATA - (continued)

	Oxford Resource Partners, LP Years Ended December 31,
	2013			2012			2011			2010			2009
	(in thousands, except per ton amounts)
STATEMENT OF CASH FLOWS DATA:
Cash flows from:
Operating activities	$	9,676		$	33,587		$	41,288		$	36,184		$	36,866
Investing activities		(12,873	)		(9,870	)		(38,198	)		(80,810	)		(47,400	)
Financing activities		2,309			(22,772	)		(947	)		42,149			(2,558	)
OTHER FINANCIAL DATA:
Adjusted EBITDA (3)	$	42,107		$	47,917		$	58,785		$	58,327		$	62,862
Capital expenditures		20,297			24,476			39,047			92,133			35,692
Cash reclamation expenditures		8,222			8,966			5,491			3,430			3,358
BALANCE SHEET DATA (at period end):
Cash	$	3,089		$	3,977		$	3,032		$	889		$	3,366
Accounts receivable		25,850			19,792			28,388			28,108			24,403
Inventory		13,840			12,554			12,000			12,640			8,801
Property, plant and equipment, net		144,426			158,483			195,607			198,694			149,461
Total assets		224,355			220,899			261,265			261,071			203,363
Total debt (current and long-term)		163,276			144,527			143,755			102,986			95,711
OPERATING DATA:
Produced tons		6,147			6,817			8,078			7,417			5,781
Purchased tons		455			533			380			734			530
Tons of coal sold		6,602			7,350			8,458			8,151			6,311
Tons sold under long-term contracts (4)		96.7	%		95.9	%		96.6	%		95.9	%		97.8	%
Coal sales revenue per ton	$	50.93		$	49.65		$	46.23		$	42.95		$	45.42
Below-market sales contract amortization per ton		(0.01	)		(0.08	)		(0.11	)		(0.17	)		-
Cash coal sales revenue per ton		50.92			49.57			46.12			42.78			45.42
Cash cost of coal sales per ton		(43.99	)		(42.51	)		(39.02	)		(35.13	)		(37.87	)
Cash margin per ton	$	6.93		$	7.06		$	7.10		$	7.65		$	7.55

(1) On September 30, 2009, we acquired all of the active Illinois Basin surface mining operations of Phoenix Coal. The purchase price of this acquisition was less than the fair value of the net assets and liabilities we acquired. We recorded this difference as a gain of $3.8 million for the year ended December 31, 2009.

(2) Excludes amounts distributed as part of the initial public offering.

(3) Adjusted EBITDA is not defined in GAAP. Adjusted EBITDA is presented because it is helpful to management, industry analysts, investors and lenders in assessing the financial performance and operating results of our fundamental business activities. For a definition of Adjusted EBITDA and a reconciliation of Adjusted EBITDA to its most directly comparable financial measures calculated and presented in accordance with GAAP, please see “Non-GAAP Financial Measures” in Part II, Item 6 – Selected Financial and Operating Data.

(4) Represents the percentage of the tons of coal we sold that were delivered under long-term coal sales contracts.

Non-GAAP Financial Measures

Adjusted EBITDA

Adjusted EBITDA represents net (loss) income before interest, income taxes, depreciation, depletion, and amortization (“DD&A”), impairment and restructuring expenses, gain or loss on the disposal of assets, amortization of below-market coal sales contracts, non-cash equity-based compensation expense, non-cash changes in mine reclamation obligations and certain non-recurring costs. Although Adjusted EBITDA is not a measure of performance calculated in accordance with GAAP, we believe it is useful in evaluating our financial performance and compliance with certain credit facility financial covenants. Because not all companies calculate Adjusted EBITDA in the same way, our calculation may not be comparable to similarly titled measures of other companies.

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

• our financial performance without regard to financing methods, capital structure or income taxes;

• our ability to generate cash sufficient to pay interest and principal on our indebtedness;

• our compliance with certain credit facility financial covenants; and

• our ability to fund capital expenditure projects from operating cash flow.

Reconciliation to GAAP Measures

The following table presents a reconciliation of net (loss) income to Adjusted EBITDA for each of the periods indicated:

Reconciliation of net (loss) income to Adjusted EBITDA

	Year Ended December 31,
	2013			2012			2011			2010			2009
	(in thousands)
Net (loss) income	$	(23,700	)	$	(26,053	)	$	(8,329	)	$	(641	)	$	29,399
Adjustments:
Interest expense, net of interest income		21,050			11,490			9,857			9,499			6,449
Depreciation, depletion and amortization		48,081			51,170			51,905			42,329			25,902
Change in fair value of warrants		(3,280	)		-			-			-			-
Impairment and restructuring expenses		1,761			15,650			-			-			-
(Gain) loss on disposal of assets, net		(6,488	)		(8,021	)		1,352			1,228			1,177
Below-market coal sales contract amortization		(60	)		(623	)		(939	)		(1,424	)		(1,705	)
Non-cash equity-based compensation expense		1,441			1,262			1,077			942			472
Non-cash changes in mine reclamation obligations		2,293			1,567			3,355			5,742			4,991
Non-recurring costs:
Debt refinancing expenses		3,109			-			-			-			-
Other		(2,100	)		1,475			507			652			(3,823	)
Adjusted EBITDA	$	42,107		$	47,917		$	58,785		$	58,327		$	62,862

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Item 7.            Management’s Discussion and Analysis of Financial Condition and Results of Operations

The following discussion contains forward-looking statements that include numerous risks and uncertainties. Actual results could differ materially from those discussed in the forward-looking statements as a result of these risks and uncertainties, including those set forth in this Annual Report on Form 10-K under “Risk Factors.” You should read the following discussion in conjunction with “Selected Financial and Operating Data” and the audited consolidated financial statements and notes thereto of Oxford Resource Partners, LP and its subsidiaries appearing elsewhere in this Annual Report on Form 10-K.

Overview

We are a low-cost producer and marketer of high-value thermal coal to U.S. utilities and industrial users, and we are the largest producer of surface mined coal in Ohio. 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 Company-Kentucky, LLC and Harrison Resources. All of our operating subsidiaries participate primarily in the business of utilizing surface mining techniques to extract coal and prepare it for sale to our customers. All three subsidiaries share common customers, assets and employees.

Currently, we have 16 active surface mines and manage these mines as six mining complexes. Our operations also include a river terminal, strategically located in eastern Ohio. For the year ended December 31, 2013, we generated revenues of $346.8 million and had a net loss of $23.7 million. For the year ended December 31, 2013, we produced 6.1 million tons of coal, purchased 0.5 million tons of coal, and sold 6.6 million tons of coal. Of the coal tons sold, 96.7% were sold pursuant to long-term coal supply contracts.

Recent Developments

Illinois Basin Restructuring

As previously disclosed in our public filings, 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, with respect to the Illinois Basin operations, we idled a mine and the related preparation plant, closed our 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 production has been idled, with the redeployment of the remaining Illinois Basin equipment being moved to our Northern Appalachian operations expected to be completed 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.

Sale of Oil and Gas Mineral Rights

In June 2013 and April 2012, we completed the sale of certain oil and gas rights on land in eastern Ohio for $6.1 million and $6.3 million, respectively, and future royalties. We expect royalty revenues to be generated from these rights in the future.

Credit Facilities

In June 2013, we closed on $175 million of credit facilities that replaced our previous term loan and revolving credit facility. These facilities include (i) a first lien credit facility consisting of a $75 million term loan and a $25 million revolver under a financing agreement (the “First Lien Financing Agreement”) and (ii) a second lien credit facility consisting of a $75 million term loan (with an option for an additional $10 million term loan if requested by us and approved by the second lien lender) under a financing agreement (the “Second Lien Financing Agreement,” and collectively with the First Lien Financing Agreement, the “Financing Agreements”).

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The first lien credit facility matures in September 2015 with an option to extend to June 2016, and the second lien credit facility matures in December 2015 with an option to extend to September 2016, if certain conditions are met. As of December 31, 2013, the blended cash interest rate for both credit facilities was 9.53%. The Financing Agreements contain customary financial and other covenants, and also preclude making unitholder distributions during the terms of the credit facilities. Borrowings under the credit facilities are secured by substantially all of our assets. The initial net proceeds of the credit facilities were used to retire our previous revolving credit and term loan credit facility, to cash collateralize certain existing letters of credit, and to pay fees and expenses related to the credit facilities. As of December 31, 2013, we were in compliance with all covenants under the Financing Agreements.

Warrants

In conjunction with the Second Lien Financing Agreement, certain lenders and lender affiliates received warrants entitling them to purchase an aggregate of 1,955,666 common units and 1,814,185 subordinated units at $0.01 per unit. The warrants participate in distributions whether or not exercised. During the five-year term for exercise of the warrants, the warrant exercise price and number of units will be adjusted for unit splits or reverse splits, such that the economics of the warrants remain unchanged. The warrants are free standing financial instruments, within the scope of ASC 480, Distinguishing Liabilities from Equity, since they are detachable from the Second Lien Financing Agreement. The warrants, classified as a liability, were recorded at their fair value of $7.9 million at issuance. The warrants are subsequently marked to fair value with the change in fair value reported in earnings. The fair value assigned to the warrants at issuance was recorded as a debt discount, reducing the outstanding debt balance. This discount will be amortized through interest expense over the life of the second lien credit facility using the effective interest method. For the year ended December 31, 2013, the fair value of the warrants decreased $3.3 million. See Note 11 for fair value disclosures.

First Lien Credit Facility

As of December 31, 2013, we had a term loan of $69.3 million outstanding under the first lien credit facility. We are obligated to make quarterly principal payments of $1.3 million commencing in June 2014, with repayment of the then outstanding balance at maturity. Borrowings on the term loan bear interest at a variable rate per annum equal to, at our option, the London Interbank Offered Rate (“LIBOR”) (floor of 1.5%) plus 6.75% or the Reference Rate (as defined in the First Lien Financing Agreement) (floor of 3.00%) plus 6.25%. As of December 31, 2013, the first lien credit facility term loan had a cash interest rate of 8.25%, consisting of LIBOR of 1.5% plus 6.75%.

The first lien credit facility also includes a $25 million revolving credit facility under which $19.5 million was outstanding as of December 31, 2013. The revolving credit facility bears interest at the same rates as the term loan under the first lien credit facility. As of December 31, 2013, the balance outstanding on the revolving credit facility had a weighted average cash interest rate of 8.76%, consisting of either LIBOR of 1.5% plus 6.75% or the Reference Rate of 3.25% plus 6.25%.

Second Lien Credit Facility

A portion of the $75 million of principal associated with the term loan under the second lien credit facility was allocated to the warrants in an amount equal to their fair value of $7.9 million at issuance. The value allocated to the warrants was recorded as a debt discount, with the remaining $67.1 million assigned to the term loan. The debt discount is being amortized to interest expense over the life of the second lien credit facility using the effective interest method. Amortization of the debt discount totaled $1.5 million for the year ended December 31, 2013.

We are obligated to make quarterly principal payments of $0.2 million on the term loan under the second lien credit facility commencing in June 2014, with repayment of the then outstanding balance at maturity. The term loan bears cash interest at a variable rate per annum equal to, at our option, LIBOR (floor of 1.25%) plus 9.75% or the Reference Rate (as defined in the Second Lien Financing Agreement) (floor of 3.00%) plus 11.75%. As of December 31, 2013, the second lien credit facility term loan had a cash interest rate of 11.00%, consisting of LIBOR of 1.25% plus 9.75%. The second lien credit facility also provides for PIK Interest (paid-in-kind interest as defined in the Second Lien Financing Agreement) at the rate of 5.75%. PIK Interest is added quarterly to the then-outstanding principal amount of the term loan as additional principal obligations. PIK Interest totaled $2.3 million for the year ended December 31, 2013.

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As of December 31, 2013, the outstanding balance on the second lien term loan was $70.9 million. This amount represents the principal balance of $75.0 million, plus PIK Interest of $2.3 million, net of the unamortized debt discount of $6.4 million.

Factors That Impact Our Business

Our results of operations in the near term could be impacted by a number of factors, including (1) adverse weather conditions and natural disasters, (2) poor mining conditions resulting from geological conditions or the effects of prior mining, (3) equipment problems, (4) the availability of transportation for coal shipments and (5) the availability and costs of key supplies and commodities such as steel, diesel fuel and explosives.

On a long-term basis, our results of operations could be impacted by, among other factors, (1) changes in governmental regulation, (2) the availability and prices of competing electricity-generation fuels, (3) our ability to secure or acquire high-quality coal reserves and (4) our ability to find buyers for coal under favorable supply contracts.

We have historically sold most of our coal through supply contracts and anticipate that we will continue to do so. As of December 31, 2013, we had commitments under supply contracts to deliver 5.2 million, 4.1 million, 2.1 million and 2.1 million tons of coal to customers in 2014, 2015, 2016 and 2017, respectively. Of these amounts, in each of 2014 and 2015, 1.7 million tons are to be priced based on market indices, in 2015, 2.1 million tons are dependent upon reaching agreement on pricing during reopener periods, and in each of 2016 and 2017, all 2.1 million tons are dependent upon reaching agreement on pricing during reopener periods.

Evaluating Our Results of Operations

We evaluate our results of operations based on several key measures, which include:

• our coal production, sales volume and sales prices, which drive our coal sales revenue;

• our cost of coal sales, including cost of purchased coal;

• our net (loss) income; and

• our Adjusted EBITDA, a non-GAAP financial measure.

Coal Production, Sales Volume and Sales Prices

We evaluate our operations based on the volume of coal we produce, the volume of coal we sell, and the prices we receive for our coal. The volume of coal we sell is also a function of the productive capacity of our mining complexes, the amount of coal we purchase, and market demand. We sell substantially all of our coal under long-term coal sales contracts, and thus sales prices are dependent upon the terms of those contracts. Please read "— Cost of Coal Sales" for more information regarding our purchased coal.

Our long-term coal sales contracts typically provide for fixed prices, or a schedule of prices that are either fixed or contain market-based adjustments, over the contract term. In addition, many of our long-term coal sales contracts have full or partial cost pass through or cost adjustment provisions. Cost pass through provisions increase or decrease the coal sales price for all or a specified percentage of changes in the costs for items such as fuel and inflation. 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, including cost-related indices for fuel and the cost-of-living generally.

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We evaluate the price we receive for our coal on a per ton basis. Our coal sales revenue per ton represents our coal sales revenue divided by total tons of coal sold. The following table provides operational data including data with respect to our coal production and purchases, coal sold and coal sales revenue per ton for the periods indicated:

										% Change
	Year Ended December 31,									2013 vs.			2012 vs.
	2013			2012			2011			2012			2011
	(in thousands)
Tons of coal sold :
Produced tons		6,147			6,817			8,078			(9.8	%)		(15.6	%)
Purchased tons		455			533			380			(14.6	%)		40.3	%
Total		6,602			7,350			8,458			(10.2	%)		(13.1	%)
Tons sold under long-term contracts (1)		96.7	%		95.9	%		96.6	%	n/a			n/a
Coal sales revenue per ton	$	50.93		$	49.65		$	46.23			2.6	%		7.4	%
Below-market sales contract amortization per ton		(0.01	)		(0.08	)		(0.11	)		(87.5	%)		(27.3	%)
Cash coal sales revenue per ton		50.92			49.57			46.12			2.7	%		7.5	%
Cash cost of coal sales per ton		(43.99	)		(42.51	)		(39.02	)		3.5	%		8.9	%
Cash margin per ton	$	6.93		$	7.06		$	7.10			(1.8	%)		(0.6	%)
Number of operating days		254.3			268.9			270.3			(5.4	%)		(0.5	%)

______________________

(1) Represents the percentage of the tons of coal we sold that were delivered under long-term coal sales contracts.

Cost of Coal Sales

We evaluate, on a cost per ton sold basis, our cost of coal sales which excludes non-cash costs such as DD&A, gain/loss on asset disposals, impairment and restructuring expenses, and indirect costs such as selling, general and administrative expenses. Our cost of coal sales per ton represents our cost of coal sales divided by the tons of coal sold. Our cost of coal sales includes costs for labor, fuel, oil, explosives, royalties, equipment lease expense, repairs and maintenance, and other costs directly related to our mining operations.

We purchase coal from third parties to fulfill a portion of our obligations under our long-term coal sales contracts and, in certain cases, to meet customer coal quality specifications. These costs are included in the cost of purchased coal amount within cost of coal sales.

The following table provides summary information for the periods indicated relating to our cost of coal sales per ton, produced tons, purchased tons and tons of coal sold:

							% Change
	Year Ended December 31,							2013 vs.		2012 vs.
	2013		2012		2011			2012		2011
	(tons in thousands)
Cost of coal sales per ton	$	43.99	$	42.51	$	39.02		3.6	%	8.8	%
Tons of coal sold:
Produced tons		6,147		6,817		8,078		(9.8	%)	(15.6	%)
Purchased tons		455		533		380		(14.6	%)	40.3	%
Total		6,602		7,350		8,458		(10.2	%)	(13.1	%)

Adjusted EBITDA

For a definition of Adjusted EBITDA and a reconciliation of net (loss) income to Adjusted EBITDA, please see “Part II, Item 6 - Selected Financial and Operating Data - Non-GAAP Financial Measures.” Please also see “Results of Operations — Summary” for a reconciliation of net (loss) income attributable to our unitholders to Adjusted EBITDA for the period indicated.

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Results of Operations

Factors Affecting the Comparability of Our Results of Operations

The comparability of our results of operations was impacted by impairment and restructuring expenses resulting from the actions taken with respect to our Illinois Basin operations as described above under "Overview." For additional information regarding impairment and restructuring expenses, refer to Note 3: Impairment and Restructuring Expenses to the audited consolidated financial statements included elsewhere in this report.

Summary

The following table sets forth certain information regarding our revenues, operating expenses, other income and expenses, and operational data for the years ended December 31, 2013, 2012 and 2011:

SELECTED FINANCIAL AND OPERATING DATA

	Year Ended December 31,
	2013			2012			2011
	(in thousands)
STATEMENT OF OPERATIONS DATA:
REVENUE:
Coal sales	$	336,201		$	364,928		$	391,046
Other revenues		10,566			8,599			9,331
Total revenues		346,767			373,527			400,377
COSTS AND EXPENSES:
Cost of coal sales:
Produced coal		268,130			288,782			316,574
Purchased coal		22,297			23,685			13,480
Total cost of coal sales (excluding depreciation, depletion and amortization)		290,427			312,467			330,054
Cost of other revenue		1,619			1,195			1,799
Depreciation, depletion and amortization		48,081			51,170			51,905
Selling, general and administrative expenses		17,297			15,629			13,739
Impairment and restructuring expenses		1,761			15,650			-
(Gain) loss on disposal of assets		(6,488	)		(8,021	)		1,352
Total costs and expenses		352,697			388,090			398,849
(LOSS) INCOME FROM OPERATIONS:		(5,930	)		(14,563	)		1,528
Interest income		4			10			13
Interest expense		(21,054	)		(11,500	)		(9,870	)
Change in fair value of warrants		3,280			-			-
NET LOSS		(23,700	)		(26,053	)		(8,329	)
Net income attributable to noncontrolling interest		(1,225	)		(755	)		(4,748	)
Net loss attributable to Oxford Resource Partners, LP unitholders	$	(24,925	)	$	(26,808	)	$	(13,077	)

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The following table presents a reconciliation of Net loss to Adjusted EBITDA for the years ended December 31, 2013, 2012 and 2011:

Reconciliation of Net loss to Adjusted EBITDA(1):

	Year Ended December 31,
	2013			2012			2011
	(in thousands)
Net loss	$	(23,700	)	$	(26,053	)	$	(8,329	)
Adjustments:
Interest expense, net of interest income		21,050			11,490			9,857
Depreciation, depletion and amortization		48,081			51,170			51,905
Change in fair value of warrants		(3,280	)		-			-
Impairment and restructuring expenses		1,761			15,650			-
(Gain) loss on disposal of assets, net		(6,488	)		(8,021	)		1,352
Amortization of below-market coal sales contracts		(60	)		(623	)		(939	)
Non-cash equity-based compensation expense		1,441			1,262			1,077
Non-cash changes in mine reclamation obligations		2,293			1,567			3,355
Non-recurring items:
Debt refinancing expenses		3,109			150			-
Other		(2,100	)		1,325			507
Adjusted EBITDA		42,107			47,917			58,785

(1) For our definition of Adjusted EBITDA, which is a non-GAAP financial measure, and for a reconciliation of this measure to our net (loss) income, please see “Part II, Item 6: Selected Financial and Operating Data – Non-GAAP Financial Measures.”

Year Ended December 31, 2013 Compared to Year Ended December 31, 2012

Overview

Total revenue was $346.8 million for the year ended December 31, 2013, a decrease of $26.7 million, or 7.2%, from $373.5 million for the year ended December 31, 2012. Net loss for the year ended December 31, 2013 was $23.7 million, compared to a net loss for the year ended December 31, 2012 of $26.1 million. Adjusted EBITDA was $42.1 million for the year ended December 31, 2013, a decrease of $5.8 million from $47.9 million for the year ended December 31, 2012. Cash margin per ton was $6.93 for the year ended December 31, 2013, a decrease of $0.13, or 1.8%, per ton from $7.06 per ton for the year ended December 31, 2012.

Coal Sales Revenue

Coal sales revenue was $336.2 million for the year ended December 31, 2013, a decrease of $28.7 million, or 7.9%, from $364.9 million for the year ended December 31, 2012. The decrease was primarily attributable to a 10.2% reduction in sales tons in the amount of $37.1 million that was a result of the lower sales volume from the Illinois Basin operations, partially offset by a $1.28 per ton, or an aggregate $8.4 million, increase in coal sales revenue for the year ended December 31, 2013.

Other Revenue

Other revenue, primarily from clay and limestone sales, royalty income and other miscellaneous revenue, was $10.6 million for the year ended December 31, 2013, an increase of $2.0 million, or 22.9%, from $8.6 million for the year ended December 31, 2012. Other miscellaneous revenue increased $4.1 million to $5.2 million for the year ended December 31, 2013 from $1.1 million for the year ended December 31, 2012, due primarily to one-time payments totaling $2.4 million for lost coal in connection with granting third-party right-of-way access through small portions of various mines and a $2.1 million settlement payment from a former coal supplier supporting sales from our Illinois Basin operations made pursuant to a settlement agreement entered into in February 2013. The $4.1 million increase in non-coal revenue was offset by $1.5 million and $0.6 million decreases in royalty income and clay and limestone sales, respectively. Royalty income was de minimis for the year ended December 31, 2013 due to a temporary cessation of production at an underground mine leased to a third party, as compared to royalty income of $1.5 million for the year ended December 31, 2012. Clay and limestone sales were $5.4 million for the year ended December 31, 2013, a decrease of $0.6 million, or 10.0%, from $6.0 million for the year ended December 31, 2012.

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Cost of Coal Sales (Excluding DD&A)

Cost of coal sales (excluding DD&A) was $290.4 million for the year ended December 31, 2013, a decrease of $22.1 million, or 7.1%, from $312.5 million for the year ended December 31, 2012. The decrease was primarily attributable to a reduction of 0.7 million in tons sold, which corresponds to a $31.9 million decrease in cost of coal sales, partially offset by an increase in the cost to produce coal of $1.48 per ton, or an aggregate $9.8 million, for the year ended December 31, 2013. Cost of coal sales per ton was $43.99 for the year ended December 31, 2013, an increase of $1.48, or 3.5%, per ton from $42.51 per ton for the year ended December 31, 2012. The $1.48 per ton increase was primarily attributable to a $0.75 per ton, or $4.9 million, increase in transportation expense, a $0.43 per ton, or $2.9 million, increase in tire expense, a $0.30 per ton, or $2.0 million, increase in wages, a $0.26 per ton, or $1.7 million, increase in explosives and a $0.15 per ton, or $1.0 million, increase in purchased coal, partially offset by a $0.23 per ton, or $1.5 million, decrease in diesel fuel expense. Transportation expense increased due to longer haul routes, wages increased due to raises as the labor market became more competitive due to the growing oil and gas drilling business in southeastern Ohio, and diesel fuel expense decreased due to lower spot prices.

For the year ended December 31, 2013, 455,000 tons of coal were purchased at an average price of $49.04 per ton, which represents a decrease of 78,000 tons purchased at an increased cost of $4.62 per ton, or $2.1 million, compared to 533,000 tons of coal purchased at an average price of $44.42 per ton for the year ended December 31, 2012.

Depreciation, Depletion and Amortization

DD&A expense was $48.1 million for the year ended December 31, 2013, a decrease of $3.1 million, or 6.0%, from $51.2 million for the year ended December 31, 2012. Depreciation expense decreased $3.5 million, or 10.0%, to $30.8 million for the year ended December 31, 2013, from $34.3 million for the year ended December 31, 2012, which decrease was primarily attributable to the restructuring related to our Illinois Basin operations. Depletion expense was $4.5 million for the year ended December 31, 2013, a $0.4 million decrease from $4.9 million for the year ended December 31, 2012, which decrease was primarily attributable to producing 0.7 million fewer tons of coal for the year ended December 31, 2013 compared to the year ended December 31, 2012. These decreases in depreciation and depletion expenses were offset in part by a $0.8 million increase in amortization expense for the year ended December 31, 2013. Increase in amortization expense of $0.8 million, to $12.8 million, for the year ended December 31, 2013, from $12.0 million for the year ended December 31, 2012, was primarily attributable to an increase in the estimated cost of reclamation work.

Selling, General and Administrative Expenses

Selling, general and administrative expenses were $17.3 million for the year ended December 31, 2013, an increase of $1.7 million, or 10.7%, from $15.6 million for the year ended December 31, 2012. The increase includes $3.1 million of fees, primarily for advisor and legal services, related to the refinancing of our credit facility, offset in part by decreases in employee benefits and contract labor expenses. Employee benefits decreased as no discretionary employer retirement plan contribution was provided for in the year ended December 31, 2013.

Impairment and Restructuring Expenses

Impairment and restructuring expenses were $1.8 million for the year ended December 31, 2013, a decrease of $13.9 million from $15.7 million for the year ended December 31, 2012. The year ended December 31, 2013 included $1.8 million of restructuring expenses consisting of equipment transportation costs, employee severance costs, and coal lease termination costs associated with the restructuring relating to our Illinois Basin operations. The year ended December 31, 2012 included $2.9 million of similar restructuring expenses and $12.8 million in asset impairment charges.

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(Gain) Loss on Disposal of Assets, Net

The net gain on disposal of assets of $6.5 million for the year ended December 31, 2013 represents a decrease of $1.5 million from a net gain on disposal of assets of $8.0 million for the year ended December 31, 2012. The $6.5 million net gain for the year ended December 31, 2013 consisted of a net gain of $6.1 million from the sale of oil and gas rights and a $1.5 million net gain resulting from $3.1 million of insurance proceeds received on equipment lost in mining activities with a carrying value of $1.6 million, offset in part by $1.1 million of net losses generated from the disposal of equipment in the normal course of business. The $8.0 million net gain for the year ended December 31, 2012 consisted of a net gain of $6.3 million from the sale of oil and gas rights and $1.7 million in net gains from the disposal of equipment in the normal course of business.

Net Income Attributable to Noncontrolling Interest

Net income attributable to noncontrolling interest relates to the 49% ownership interest in Harrison Resources owned by a subsidiary of CONSOL. Net income attributable to noncontrolling interest was $1.2 million for the year ended December 31, 2013, an increase of $0.4 million from $0.8 million for the year ended December 31, 2012. This increase in net income attributable to noncontrolling interest was primarily due to lower operating costs at the Harrison mine.

Year Ended December 31, 2012 Compared to Year Ended December 31, 2011

Overview

Total revenue was $373.5 million for the year ended December 31, 2012, a decrease of $26.9 million, or 6.7%, from $400.4 million for the year ended December 31, 2011. Net loss for the year ended December 31, 2012 was $26.1 million, compared to a net loss for the year ended December 31, 2011 of $8.3 million. Adjusted EBITDA was $47.9 million for the year ended December 31, 2012, a decrease of $10.9 million from $58.8 million for the year ended December 31, 2011. Cash margin per ton was $7.06 for the year ended December 31, 2012, a decrease of $0.04 per ton, or 0.6%, from $7.10 per ton for the year ended December 31, 2011.

Coal Sales Revenue

Coal sales revenue was $364.9 million for the year ended December 31, 2012, a decrease of $26.1 million, or 6.7%, from $391.0 million for the year ended December 31, 2011. The decrease was primarily attributable to a 13.1% reduction in sales tons in the amount of $51.2 million that was a result of the lower sales volume from the Illinois Basin operations. The decrease was partially offset by a $3.42 increase in cash coal sales revenue per ton that increased coal sales revenue by $25.1 million.

Other Revenue

Other revenue, consisting primarily of limestone sales, service contract income, royalty income and other miscellaneous revenue, was $8.6 million for the year ended December 31, 2012, a decrease of $0.7 million, or 7.8%, from $9.3 million for the year ended December 31, 2011. Limestone sales were $5.9 million and miscellaneous revenue was $1.2 million for the year ended December 31, 2012, an increase of $2.4 million and $0.1 million, respectively, from $3.5 million and $1.1 million, respectively, for the year ended December 31, 2011. This increase was more than offset by a decrease in royalty income and service contract income of $1.7 million and $1.5 million, respectively.

Cost of Coal Sales (Excluding DD&A)

Cost of coal sales (excluding DD&A) was $312.5 million for the year ended December 31, 2012, a decrease of $17.6 million, or 5.3%, from $330.1 million for the year ended December 31, 2011. The decrease was primarily attributable to a reduction of 1.1 million in tons sold, which corresponds to a $43.2 million decrease in cost of coal sales. The reduction in tons sold was attributable to the lower sales volume from the Illinois Basin operations. Cost of coal sales per ton was $42.51 for the year ended December 31, 2012, an increase of $3.49, or 8.9%, per ton from $39.02 per ton for the year ended December 31, 2011. The $3.49 per ton increase corresponds to a $25.7 million increase in cost of coal sales, primarily attributable to an increase of $12.0 million in the cost of purchased coal, an increase of $10.8 million in the cost of diesel fuel and an increase of $4.7 million in lease expense, partially offset by decreases in the cost of supplies of $0.9 million and in wages and employee benefits costs of $0.8 million. For the year ended December 31, 2012, 533,198 tons of coal were purchased at an average price of $44.42 per ton, which represents increases of 153,229 tons and $8.94 per ton, compared to 379,968 tons of coal purchased at an average price of $35.47 per ton for the year ended December 31, 2011. The diesel fuel expense increased due to higher spot prices, partially offset by producing fewer tons. Lease expense increased as it was decided to replace owned mining equipment that was retired with leased mining equipment. Transportation expense decreased due to the reduction in tons shipped, partially offset by an increase in per ton transportation costs.

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Depreciation, Depletion and Amortization

DD&A expense was $51.2 million for the year ended December 31, 2012, a decrease of $0.7 million, or 1.4%, from $51.9 million for the year ended December 31, 2011. In 2012, certain equipment associated with our Illinois Basin operations was reclassified to assets held for sale and is no longer being depreciated. The decrease in depreciation was partially offset by a $2.8 million increase in amortization of reclamation and mine development costs for open mines due to higher costs.

Selling, General and Administrative Expenses

Selling, general and administrative expenses were $15.6 million for the year ended December 31, 2012, an increase of $1.9 million, or 13.7%, from $13.7 million for the year ended December 31, 2011. The increase was primarily attributable to higher professional fees and compensation expense.

Impairment and Restructuring Expenses 

Impairment and restructuring expenses were $15.7 million for the year ended December 31, 2012. No such expenses were incurred for the year ended December 31, 2011. These expenses consisted of severance costs, asset impairment charges, professional fees and equipment transportation costs associated with the restructuring of our Illinois Basin operations.

(Gain) Loss on Disposal of Assets

The gain on disposal of assets of $8.0 million for the year ended December 31, 2012 represents an increase of $9.4 million from a loss of $1.4 million for the year ended December 31, 2011. The aggregate gain of $10.2 million, which substantially resulted from the sale of oil and gas rights and reclaimed land, was partially offset by losses generated from the sale/disposal of equipment in the normal course of business.

Net Income Attributable to Noncontrolling Interest

Net income attributable to noncontrolling interest represents the net income attributable to the 49% interest in Harrison Resources owned by a subsidiary of CONSOL. Net income attributable to noncontrolling interest was $0.8 million for the year ended December 31, 2012, a decrease of $4.0 million from $4.8 million for the year ended December 31, 2011. This decrease in net income attributable to noncontrolling interest was primarily due to increased mining costs resulting from a higher strip ratio incurred at the Harrison mine.

Liquidity and Capital Resources

Liquidity

Our business is capital intensive and requires substantial capital expenditures for, among other things, purchasing, maintaining and upgrading equipment used in developing and mining our coal, and acquiring reserves. Our principal liquidity needs are to finance current operations and fund capital expenditures, including costs of acquisitions from time to time, servicing of our debt and paying cash distributions to our unitholders when we are in a position to do so. Our primary sources of liquidity to meet these needs are cash generated by our operations and borrowings under the Financing Agreements. Also, if we are able to sell the remaining excess Illinois Basin equipment, a large-capacity shovel and several smaller pieces of equipment, our liquidity will be enhanced. Additionally, we would consider offers for the remaining coal reserves and/or facilities related to our Illinois Basin operations, which could further enhance our liquidity.

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Our ability to satisfy our working capital requirements, meet debt service obligations, and fund planned capital expenditures substantially depends upon our future operating performance, which may be affected by prevailing economic conditions in the coal industry. To the extent our future operating cash flow or access to financing sources and the costs thereof are materially different than expected, our future liquidity may be adversely affected.

Our consolidated financial statements have been prepared assuming that we will continue as a going concern. We have incurred net losses in the past few years resulting in an accumulated deficit of $ 10,998 at December 31 2013. We have managed our liquidity for the year ended December 31, 2013, with $9,676 of cash flows provided from operations and $2,309 of cash flows provided from financing activities. As of December 31, 2013, our available liquidity was S8.2 million, which consisted of $3.1 million in cash on hand and $5.1 million of borrowing capacity under the Financing Agreements.

Should we have difficulty meeting our forecasts, this could have an adverse effect on our liquidity position. Management has taken the following actions to improve its liquidity position:

• restructured our lllinois Basin operations;

• aligned our coal production with our committed coal sales and reduced cost by temporarilyidling production at two Northern Appalachian mines and eliminating approximately 50 positions;

• reduced capital expenditures; and

• acquired a strategically located coal preparation plant next to a significant customer that will reduce coal transportation costs.

Through the aforementioned actions, management expects to be able to achieve its forecasted results for the year ending December 31, 2014. However, there can be no assurance that our cash flows will be sufficient to allow us to continue as a going concern if we are unable to meet our projections.

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

Cash Flows

The following table reflects cash flows for the years indicated:

	Year Ended December 31,
	2013			2012			2011
	(in thousands)
Net cash provided by (used in):
Operating activities	$	9,676		$	33,587		$	41,288
Investing activities		(12,873	)		(9,870	)		(38,198	)
Financing activities		2,309			(22,772	)		(947	)

Year Ended December 31, 2013 Compared to Year Ended December 31, 2012

Net cash provided by operating activities was $9.7 million for the year ended December 31, 2013 compared to $33.6 million for the year ended December 31, 2012, a decrease of $23.9 million. We experienced a net loss for the year ended December 31, 2013 of $23.7 million, a decrease of $2.4 million, or 9.0%, compared to a net loss for the year ended December 31, 2012 of $26.1 million. The decrease in the net loss was attributable in part to a $13.9 million decrease in impairment and restructuring expenses related to our Illinois Basin operations and a $3.1 decrease in depreciation, depletion and amortization, partially offset by $4.1 million in non-cash interest expense, a $3.3 million change in the fair value of warrants associated with the refinancing of our credit facility, $3.1 million of expenses related to our debt refinancing, a $1.5 million decrease in the net gain on sale of assets, and a $1.8 million increase in amortization and write-off of deferred financing costs. These differences, combined with $14.8 million in unfavorable changes in working capital, are the primary drivers of the decrease in net cash provided by operating activities. The unfavorable change in working capital was primarily attributable to a $14.7 unfavorable change in accounts receivable resulting from expedited collections effort for the fiscal year ended December 31, 2012 which were not repeated for the fiscal year ended December 31, 2013.

Net cash used in investing activities was $12.9 million for the year ended December 31, 2013 compared to $9.9 million for the year ended December 31, 2012, an increase of $3.0 million. The increase was attributed to a $6.0 million reduction in proceeds from the sale of assets, partially offset by a $2.6 million increase in insurance proceeds and a favorable change of $1.3 million in the purchase of property and equipment. The $1.3 million favorable change in the purchase of property and equipment results from our ability to redeploy existing mining equipment from our Illinois Basin operations to our Northern Appalachian operations.

Net cash provided by financing activities was $2.3 million for the year ended December 31, 2013, up $25.1 million from net cash used in financing activities of $22.8 million for the year ended December 31, 2012. In the year ended December 31, 2012, we made $22.8 million of distributions to our unitholders. In the year ended December 31, 2013, we did not make any distributions to our unitholders and refinanced our credit facility which increased our debt by $20.4 million. Of this amount, $9.6 million was used to pay fees related to the refinancing and an additional $9.6 million was used to collateralize surety bonds.

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Year Ended December 31, 2012 Compared to Year Ended December 31, 2011

Net cash provided by operating activities was $33.6 million for the year ended December 31, 2012 compared to $41.3 million for the year ended December 31, 2011, a decrease of $7.7 million. The decrease was primarily attributable to a $17.8 million increase in net loss for the year ended December 31, 2012 as compared to the year ended December 31, 2011, together with a $9.4 million increase in gain on disposal of property and equipment, offset in part by $15.7 million of impairment and restructuring expenses and a $3.4 million favorable change in working capital. For the year ended December 31, 2012, an $8.0 million gain on disposal of property and equipment was recognized as the result of the sale of oil and gas rights and reclaimed land, partially offset by losses generated from the sale/disposal of equipment in the normal course of business. The $15.7 million of impairment and restructuring expenses was the result of the restructuring of our Illinois Basin operations. The unfavorable change in working capital of $3.4 million was comprised of favorable changes of $8.9 million in accounts receivable and $3.8 million in restricted cash, partially offset by unfavorable changes of $3.5 million in reclamation, $2.3 million in inventory and $1.1 million in other liabilities. The accounts receivable change is primarily due to the timing of payments in December 2012, while the unfavorable change in reclamation and mine closure costs is the result of a 2012 increase in the future obligations to reclaim land and close mines for the year ended December 31, 2012. The inventory change was primarily due to higher coal stockpile levels at year-end 2012 compared to year-end 2011.

Net cash used in investing activities was $9.9 million for the year ended December 31, 2012, compared to $38.2 million for the year ended December 31, 2011, a decrease of $28.3 million. The decrease was primarily attributable to a $14.8 million decrease in the purchase of property and equipment and $11.6 million in proceeds from the sale of property and equipment. The $14.8 million decrease in the purchase of property and equipment was attributable to satisfying mining equipment requirements in Northern Appalachia with existing mining equipment transferred from our Illinois Basin operations, and leasing as opposed to purchasing other mining equipment. Additionally, as part of our restructuring efforts for the Illinois Basin operations, we also received $11.6 million in proceeds from the sale of mining equipment.

Net cash used in financing activities was $22.8 million for the year ended December 31, 2012, up from $0.9 million for the year ended December 31, 2011. The increase of $21.9 million was primarily attributable to a $35.0 million decrease in advances on our revolving credit line and a $4.7 million reduction in our term loan, partially offset by a $14.0 million reduction in distributions to partners and a $4.9 million reduction in distributions to noncontrolling interest compared to the year ended December 31, 2011.

Capital Expenditures

Our mining operations require investments to maintain, expand, and upgrade existing operations and to meet environmental and safety regulations. We have funded and expect to continue funding capital expenditures primarily from cash generated by our operations, borrowings under the Financing Agreements, and proceeds from asset sales.

The following table summarizes our capital expenditures by type for the years ended December 31, 2013 and 2012:

	Year Ended December 31,
	2013		2012
	(in thousands)
Coal reserves	$	1,532	$	1,761
Mine development		3,027		3,402
Equipment and components		15,738		19,313
Total	$	20,297	$	24,476

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Contractual Obligations

We have contractual obligations that are required to be settled in cash. The amounts of our contractual obligations as of December 31, 2013 were as follows:

	Payment Due by Period
	Total		Less than 1 Year		1 - 3 Years		4 - 5 Years		More than 5 Years
	(in thousands)
Long-term debt obligations	$	155,985	$	4,313	$	151,672	$	-	$	-
Future interest obligations - long-term debt (1)		27,488		14,358		13,130		-		-
Other long-term debt (2)		3,733		3,728		5		-		-
Fixed-price diesel fuel purchase contracts		36,708		36,708		-		-		-
Operating lease obligations		17,170		7,928		9,240		2		-
Total	$	241,084	$	67,035	$	174,047	$	2	$	-

(1)	Interest on variable rate long-term debt was calculated using rates estimated by us at December 31, 2013 for the remaining term of outstanding borrowings.
(2)	Represents various notes payable with interest rates ranging from 5.0% to 6.75%.

Off-Balance Sheet Arrangements

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

Federal and state laws require us to secure certain long-term obligations, such as reclamation and mine closure costs, and contractual performance. Historically, we secured these obligations with surety bonds supported by letters of credit. Subsequent to our refinancing, we have supported our surety bonds with cash deposits.

As of December 31, 2013, we had $37.0 million of surety bonds outstanding and $0.4 million of cash bonds to secure certain reclamation obligations. Additionally, as of December 31, 2013, we had $9.6 million of cash deposits in support of these bonds. Further, as of December 31, 2013, we had $0.6 million of road bonds and $2.1 million of performance bonds outstanding that required no security. We believe these bonds and letters of credit will expire without any claims or payments thereon, and accordingly we do not expect any material adverse effect on our financial condition, results of operations or cash flows therefrom.

Critical Accounting Policies and Estimates

Use of Estimates

Our financial statements are prepared in accordance with accounting principles that are generally accepted in the United States.  The preparation of these financial statements require management to make estimates and assumptions that affect the reported amounts of assets, liabilities, revenues and expenses, as well as the disclosures of contingent assets and liabilities.  Management evaluates its estimates and judgments on an on-going basis, and bases such estimates and judgments on historical experience and other factors that are believed to be reasonable under the circumstances.  Actual results could differ significantly from those estimates.

We have provided a summary of all significant accounting policies in Note 2, Summary of Significant Accounting Policies, to the audited consolidated financial statements presented elsewhere in this Annual Report on Form 10-K.  The most significant policies requiring the use of management estimates and assumptions relate to the collectability of accounts receivable, useful lives of fixed assets, valuation of coal reserves, reserve estimates of coal reserves, evaluations of asset impairment, recoverability of advanced royalties, useful lives of intangible assets, and estimates of future reclamation and mine closure costs. We believe that these significant policies involve a high degree of judgment and/or complexity.

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Allowance for Doubtful Accounts

We establish an allowance for losses on accounts receivable when it is probable that all or part of an outstanding balance will not be collected.  Our management regularly reviews the probability that a receivable will be collected and establishes or adjusts the allowance as necessary.

Inventory

Inventory consists of coal that has been completely uncovered or that has been removed from the pit and stockpiled for crushing, washing, or shipment to customers.  Inventory also consists of supplies, spare parts and fuel. Inventory is valued at the lower of average cost or market.  The cost of coal inventory includes certain operating expenses including overhead and stripping costs incurred during the production phase, which commences when saleable coal, beyond a de minimis amount, is produced.

Property, Plant and Equipment

Property, plant and equipment are recorded at cost.  Expenditures that extend the useful lives of existing plant and equipment are capitalized.  Maintenance and repairs that do not extend the useful life or increase productivity are charged to operating expense as incurred.  Plant and equipment are depreciated principally on the straight-line method over the estimated useful lives of the assets.

We acquire our coal reserves through purchases or leases.  We deplete our coal reserves using the units-of-production method on the basis of tonnage mined in relation to total estimated recoverable tonnage with residual surface values classified as land.

Exploration expenditures are charged to operating expense as incurred and include costs related to locating coal deposits and the drilling and evaluation costs incurred to assess the economic viability of such deposits.  Costs incurred in areas outside the boundary of known coal deposits and areas with insufficient drilling to qualify as proven and probable reserves are also expensed as exploration costs.

Once management determines there is sufficient evidence that the expenditure will result in a future economic benefit to us, the costs are capitalized as mine development costs.  Capitalization of mine development costs continues until more than a de minimis amount of saleable coal is extracted from the mine.  Amortization of these mine development costs is then initiated using the units-of-production method based upon the total estimated recoverable tonnage.

Long-Lived Assets and Asset Impairment

Long-lived assets, such as property, plant and equipment, coal reserves, mine development costs and intangible assets, are reviewed for impairment whenever events or changes in circumstances indicate that the carrying amount of an asset or asset group may not be recoverable.  Recoverability is measured by comparing the projected future cash flows from use and disposition of assets with the carrying amounts of those assets.  When the sum of projected cash flows is less than the carrying amount, impairment losses are indicated.  If the fair value of the assets is less than the carrying amount thereof, an impairment loss is recognized.  In determining such impairment losses, discounted cash flows or asset appraisals are utilized to determine the fair value of the assets being evaluated.  Assets held for sale are reported at the lower of the carrying amount or fair value less costs to sell, and are no longer depreciated.

Also, in certain situations, expected mine lives are shortened because of changes to planned operations.  When that occurs and it is determined that a mine’s underlying costs are not recoverable in the future, reclamation and mine closure obligations are accelerated by accelerating the depletion rate.  To the extent it is determined that an asset’s carrying value will not be recoverable during a shorter mine life, the asset is written down to its recoverable value.

Advance Royalties

A substantial portion of our reserves are leased.  Advance royalties are advance payments made to lessors under terms of lease agreements that are typically recoupable through an offset or credit against royalties payable on future production.  We write-off advance royalties when recoverability is no longer probable based on future mining plans.

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Intangible Assets

We have recorded intangible assets associated with certain customer relationships at fair value.  These balances arose from the purchase accounting for our acquisition of Oxford Mining and its subsidiaries.  These intangible assets are being amortized over their expected useful lives.

Reclamation and Mine Closure Costs

Our reclamation and mine closure costs arise from the Surface Mining Control and Reclamation Act (“SMCRA”) and similar state statutes, which require that mine property be restored in accordance with specified standards and an approved reclamation plan.  Our reclamation and mine closure costs are recorded initially at fair value based on the assumption that all work will be performed by third-party contractors. We estimate reclamation and mine closure costs using the end of mine life method. The end of mine life method estimates the liability based on the costs to reclaim the last pit(s) once the mine is no longer producing coal.  This liability is amortized over the tons expected to be recovered during the productive life of a mine.

To determine the fair value of our reclamation and mine closure costs, we calculate on a mine-by-mine basis the present value of estimated reclamation cash flows.  This process requires us to estimate the acreage subject to reclamation, estimate future reclamation costs, and make assumptions regarding a mine’s productivity.  These cash flows are discounted at a credit-adjusted, risk-free interest rate based on U.S. Treasury bonds with a maturity similar to the expected life of a mine.

When the liability is initially established, the offset is capitalized to the mine development asset.  Over time, the reclamation and mine closure cost liability is accreted to its present value, and the capitalized cost is depleted using the units-of-production method for the related mine.  If the assumptions used to estimate the reclamation and mine closure cost liability do not materialize as expected or regulatory changes occur, reclamation costs or obligations to perform reclamation and mine closure activities could be materially different than initially estimated.  At least annually, we review our reclamation liability and make adjustments for permit changes, cost revisions, changes to mining plans and the timing of expenditures.

Warrants

In conjunction with our refinancing in June 2013, certain of the second lien lenders and lender affiliates received warrants entitling them to purchase common and subordinated units under a freestanding contract. Pursuant to Financial Accounting Standards Board's Accounting Standards Board's Codification Topic 470-20, “Debt With Conversion and Other Options” (ASC 470-20), freestanding contracts that are settled in a company’s own stock,including common and subordinated unit warrants, are to be designated as an asset, liability or equity instrument. Both the common and subordinated unit warrants were determined to be liabilities and were recorded at fair value as determined using the Black-Scholes Pricing Model. ASC 470-20 further requires that the warrants’ fair value be remeasured each reporting period, with the change in fair value being reported in the consolidated statements of operations. Fair value determinations prepared using the Black-Scholes Pricing Model require assumptions related to interest rates, unit price, exercise price, term and volatilities.

Revenue Recognition

Revenue from coal sales is recognized and recorded when shipment or delivery to the customer has occurred, prices are fixed or determinable, and the title or risk of loss has passed. Coal sales prices are subject to premiums and reductions based on variations in the delivered coal quality versus specifications in the contract, but such adjustments are typically confirmed in a matter of days. Risk of loss typically transfers to the customer at the mine or dock, when the coal is loaded on the rail, barge, or truck.

Other revenue consists primarily of clay and limestone sales, royalty income, service fees, and other miscellaneous revenue. Clay and limestone sales relate to material we recover during the coal mining process and sell to third parties. Royalty income relates to underground coal reserves that we sublease to a third party mining company. Service fees are earned for operating a coal unloading facility, providing river barge loading services, and ash hauling. Periodically, we recognize miscellaneous revenue related to lost coal claims that result from granting third-party right-of-way access through small portions of various mines.

Item 7A.         Quantitative and Qualitative Disclosures About Market Risk

Market risk includes risks that arise from changes in interest rates, foreign currency exchange rates, commodity prices, equity prices and other market changes that affect market-sensitive instruments. We believe our principal market risks are commodity price risks and interest rate risks.

Commodity Price Risks

We manage our commodity price risks for coal sales through the use of supply contracts and the use of forward-purchase contracts.

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Some of the products used in our mining activities, such as diesel fuel and explosives, are subject to price volatility. Through our suppliers, we utilize forward-purchase contracts to manage the exposure related to this volatility. Additionally, 25.1% of our expected diesel fuel needs are protected, in varying amounts, by diesel fuel escalation provisions contained in coal supply contracts with some of our customers, allowing for a change in the price per coal ton sold. Price changes typically lag the changes in diesel fuel costs by one quarter and are recorded in coal sales. A hypothetical increase of $0.30 per gallon for diesel fuel would have increased the net loss by $1.3 million for the year ended December 31, 2013, and a hypothetical increase of 10% in explosives prices would have increased the net loss by $2.2 million for the year ended December 31, 2013.

Interest Rate Risks

We will from time to time adjust our exposure to interest rate risks by entering into interest rate swap arrangements. The effect of the interest rate swap arrangements is to convert the respective amount of debt from a variable interest rate to a fixed interest rate.

For the balance of our indebtedness that is not subject to the interest rate swap arrangements, we have exposure to changes in interest rates on our indebtedness associated with the Financing Agreements. At December 31, 2013, the weighted average cash interest rate on our debt under the Financing Agreements was 9.5%. Based on our borrowings at the end of 2013, a hypothetical 100 basis point increase in short-term interest rates would result, over the subsequent twelve-month period, in reduced net income of approximately $0.5 million.

Item8.            Financial Statements and Supplementary Data

The Report of Independent Registered Public Accounting Firm, Consolidated Financial Statements and supplementary financial data required for this Item are set forth on pages F-1 through F-31 of this Annual Report on Form 10-K and are incorporated herein by reference.

Item 9.            Changes in and Disagreements With Accountant on Accounting and Financial Disclosure

None.

Item 9A.         Controls and Procedures

Conclusion Regarding the Effectiveness of Disclosure Controls and Procedures

We carried out an evaluation, under the supervision and with the participation of management, including our chief executive officer and chief financial officer, of the effectiveness of the design and operation of our disclosure controls and procedures as of the end of the period covered by this Annual Report on Form 10-K pursuant to Securities Exchange Act of 1934 Rule 13a-15. Based upon that evaluation, our chief executive officer and chief financial officer concluded that, as of December 31, 2013, our disclosure controls and procedures were effective to provide reasonable assurance that material information required to be disclosed by us in reports that we file or submit under the Securities Exchange Act of 1934 is appropriately recorded, processed, summarized and reported within the time periods specified in the SEC’s rules and forms and that information required to be disclosed by us in the reports we file or submit under the Securities Exchange Act of 1934 is accumulated and communicated to our management, including our chief executive officer and chief financial officer, as appropriate, to allow timely decisions regarding required disclosure.

Management’s Annual Report on Internal Control Over Financial Reporting

Management is responsible for establishing and maintaining adequate internal control over financial reporting. Our internal control over financial reporting is a process designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles.

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Our internal control over financial reporting includes policies and procedures that (1) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect transactions and dispositions of assets; (2) provide reasonable assurances that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and that receipts and expenditures are being made only in accordance with authorizations of management and the directors of the company; and (3) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use or disposition of our assets that could have a material effect on our financial statements.

Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.

As of the end of the period covered by this Annual Report on Form 10-K, our management carried out an evaluation, with the participation of our chief executive officer and chief financial officer, of the effectiveness of our internal control over financial reporting (as defined in Rules 13a-15(f) and 15d-15(f) promulgated under the Securities Exchange Act of 1934, as amended). Based upon that evaluation, our chief executive officer and chief financial officer concluded that our internal control over financial reporting was effective as of the end of the period covered by this Annual Report on Form 10-K. In making this assessment, management used the criteria set forth by the Committee of Sponsoring Organizations of the Treadway Commission (COSO) in the 1992 Internal Control-Integrated Framework. The design of any system of controls is based in part upon certain assumptions about the likelihood of future events, and there can be no assurance that any design will succeed in achieving its stated goals under all potential future conditions, regardless of how remote.

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 Changes in Internal Control Over Financial Reporting

There have been no changes in our internal control over financial reporting during the quarter ended December 31, 2013 that have materially affected, or are reasonably likely to materially affect, our internal control over financial reporting.

ITEM 9B. OTHER INFORMATION

Amendment to AEP Coal Sale and Purchase Agreement

On February 27, 2014, Oxford Mining and AEP Generation Resources Inc. (successor in interest to Ohio Power Company (f/k/a Columbus Southern Power Company)) (“AEP”) completed the execution and delivery of an amendment (the “AEP-Oxford Amendment”) to the Coal Purchase and Sale Agreement between them dated as of May 21, 2004, as amended (such Coal Purchase and Sale Agreement as amended, the “AEP-Oxford Agreement”). Under the terms of the AEP-Oxford Amendment which was effective January 1, 2014, the pricing under the AEP-Oxford Agreement was set and agreed upon for 2014 based on certain market indices.

The foregoing summary of the AEP-Oxford Amendment is qualified in its entirety by reference to the full text of the AEP-Oxford Amendment, a copy of which is included with this Annual Report on Form 10-K and incorporated herein by reference. The Registrant is making a request for confidential treatment for certain terms of the AEP-Oxford Amendment, which request will be filed separately with the Securities and Exchange Commission.

Amendments to Employment Agreements for Certain Named Executive Officers

Our general partner is a party to employment agreements with each of its named executive officers, who are (i) Charles C. Ungurean, President and Chief Executive Officer, (ii) Bradley W. Harris, Senior Vice President, Chief Financial Officer and Treasurer, (iii) Daniel M. Maher, Senior Vice President, Chief Legal Officer and Secretary, (iv) Gregory J. Honish, Senior Vice President, Operations, and (v) Michael B. Gardner, Vice President - Legal, General Counsel – Regulatory/Environmental and Assistant Secretary.  These employment agreements establish customary employment terms for the named executive officers including base salaries, bonuses, other incentive compensation and other benefits and provisions for duties and titles.

Effective March 3, 2014, our general partner amended the employment agreements for each of the named executive officers other than Mr. Ungurean, extending the initial terms thereof by one (1) year to run until December 31, 2015.  Notwithstanding the automatic extension provisions set forth in such employment agreements, our general partner’s Board of Directors and its Compensation Committee considered it advisable to extend the terms early, consistent with their practice of seeking to extend the terms of executive employment agreements that they wish to have extended before the operation of automatic extension provisions. The term of Mr. Ungurean’s employment agreement extends past December 31, 2015 and as a result no extension action was taken with respect to his employment agreement.

The foregoing description of certain terms and conditions of the employment agreements for the named executive officers and the amendments thereto, and the rights and obligations of our general partner and the named executive officers in connection therewith, are qualified by reference in their entirety to the definitive terms and conditions of such employment agreements and the amendments thereto, copies of which amendments are included with this Annual Report on Form 10-K and incorporated herein by reference.

Amendment to Long-Term Incentive Plan

As previously disclosed in the Information Statement on Schedule 14C filed with the SEC on February 4, 2014 (the “Information Statement”), on December 12, 2013, the board of directors (the “Board”) of Oxford Resources GP, LLC, the general partner of the Registrant, unanimously approved a first amendment (the “LTIP Amendment”) to the Oxford Resource Partners, LP Amended and Restated Long-Term Incentive Plan (as amended, our “LTIP”), subject to unitholder approval. The purpose of the LTIP Amendment was to increase the number of common units that may be delivered with respect to awards under our LTIP by 750,000 common units. On December 31, 2013, certain unitholders holding a majority of the Registrant’s outstanding total common and subordinated units as of that date also approved the LTIP Amendment by a written consent in lieu of a special meeting of the unitholders. Such unitholders consent became effective on February 27, 2014.

Our LTIP provides for awards of options to purchase common units, common unit appreciation rights, restricted common units, phantom common units, other common unit-based awards, common units and replacement common units, including any tandem distribution equivalent rights granted with respect thereto, to employees, directors or consultants providing services to us, our general partner or affiliates thereof. Our LTIP is administered by the Compensation Committee of the Board (the “Compensation Committee”). The aggregate number of common units that may be delivered with respect to awards under our LTIP are 2,806, 075 (which has been increased by 750,000 from 2,056,075 pursuant to the LTIP Amendment), with such amount subject to adjustment as provided for under the terms of our LTIP if there is a change in common units, such as a unit split or other transaction that increases (or decreases) the number of common units outstanding. The common units authorized to be granted under our LTIP, including the additional 750,000 common units, have been registered pursuant to registration statements on Form S-8.

The terms and types of awards and participants are determined by the Compensation Committee at its discretion in accordance with our LTIP. Except as required by any award agreement, applicable law or the rules of the New York Stock Exchange, our LTIP may be amended or terminated at any time by the Board or the Compensation Committee. The Compensation Committee is also authorized to make adjustments in the terms and conditions of, and the criteria included in awards under, our LTIP in specified circumstances. Our LTIP is effective until the earliest of (i) the date it is terminated by the Board or the Compensation Committee, (ii) all common units available under our LTIP have been issued to participants, or (iii) June 18, 2020.

Because awards under our LTIP are granted at the discretion of the Compensation Committee, future benefits under our LTIP are currently not determinable.

The foregoing summary of our LTIP and the LTIP Amendment does not purport to be complete and is qualified in its entirety by reference to the full text of our LTIP and the LTIP Amendment, copies of which are included with this Annual Report on Form 10-K and incorporated herein by reference.

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PART III

Item 10.          Directors, Executive Officers and Corporate Governance

Partnership Management

We are managed and operated by the directors and executive officers of our general partner, Oxford Resources GP, LLC. Our general partner was not elected and is not subject to election in the future by our unitholders. Our general partner has a board of directors, and our unitholders are not entitled to elect the directors or directly or indirectly participate in our management or operations. Our general partner owes certain fiduciary duties to our unitholders as well as a fiduciary duty to its owners. Our general partner is liable, as general partner, for all of our debts (to the extent not paid from our assets), except for indebtedness or other obligations that are made specifically nonrecourse to it. Whenever possible, we intend to incur indebtedness that is nonrecourse to our general partner.

Our general partner’s board of directors has seven directors, three of whom are independent as defined under the independence standards established by the NYSE and the Exchange Act. Our general partner’s board of directors has affirmatively determined that Peter B. Lilly, Robert J. Messey and Gerald A. Tywoniuk are independent as described in the rules of the NYSE and the Exchange Act. The NYSE does not require a listed publicly traded partnership, such as ours, to have a majority of independent directors on the board of directors of our general partner or to establish a compensation committee or a nominating committee.

Directors and Executive Officers

Directors are appointed for a term of one year and hold office until their successors have been elected or qualified or until the earlier of their death, resignation, removal or disqualification. Officers serve at the discretion of the board. The following table shows information for the directors and executive officers of our general partner.

Name	Age	Position
George E. McCown	78	Chairman of the Board
Charles C. Ungurean	64	Director, President and Chief Executive Officer
Bradley W. Harris	54	Senior Vice President, Chief Financial Officer and Treasurer
Daniel M. Maher	68	Senior Vice President, Chief Legal Officer and Secretary
Gregory J. Honish	57	Senior Vice President, Operations
Michael B. Gardner	58	Vice President-Legal, General Counsel-Regulatory/Environmental and Assistant Secretary
Denise M. Maksimoski	39	Senior Director, Accounting
Brian D. Barlow	43	Director
Matthew P. Carbone	47	Director
Peter B. Lilly	65	Director
Robert J. Messey	68	Director
Gerald A. Tywoniuk	52	Director

George E. McCown was elected and has served as Chairman of the board of directors of our general partner in and since August 2007. Mr. McCown has been a Managing Director of AIM since he co-founded AIM in July 2006. Additionally, Mr. McCown has been a Managing Director of McCown De Leeuw & Co. (“MDC”), a private equity firm based in Foster City, California that specializes in buying and building industry-leading middle-market companies in partnership with management, since he co-founded MDC in 1983. Mr. McCown is Chairman of the board of directors of the general partner of Tunnel Hill Partners, LP, an affiliate of AIM and C&T Coal. Mr. McCown received a M.B.A. from Harvard University and a B.S. in Mechanical Engineering from Stanford University, where he served as a trustee from 1980 to 1985 and chaired the Finance Committee and Investment Policy Subcommittee.

Mr. McCown’s over 40 years of experience in buying and building companies, as well as his in-depth knowledge of the coal industry generally and our partnership in particular, provide him with the necessary skills to be a member of the board of directors of our general partner.

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Charles C. Ungurean was elected and has served as President and Chief Executive Officer and a member of the board of directors of our general partner in and since its formation in August 2007. In 1985, Mr. Ungurean co-founded our predecessor and wholly owned subsidiary, Oxford Mining Company. He served as President and Treasurer of our predecessor from 1985 to August 2007. Mr. Ungurean currently serves on the board of directors of the National Mining Association. In addition, Mr. Ungurean served as Chairman of the Ohio Coal Association from July 2002 to July 2004. Mr. Ungurean received a B.A. in General Studies from Ohio University and is a certified surface mine foreman in Ohio.

Mr. Ungurean’s more than 40 years of experience in the coal industry, over 25 of which have been spent running our operations or the operations of our predecessor and wholly owned subsidiary, Oxford Mining Company, provide him with the necessary skills to be a member of the board of directors of our general partner and a member of the Executive Committee.

Bradley W. Harris has served as Senior Vice President, Chief Financial Officer and Treasurer of our general partner since October 2012. Before joining us, he was Senior Vice President and Chief Financial Officer of Essar Resources, Inc., a subsidiary of Essar Global, Inc. that was formed to be the parent company for Trinity Coal Corporation (a Central Appalachia coal producer) and Essar Steel Minnesota Limited (a development stage iron ore producer), from July 2011 to December 2011. Prior to that, Mr. Harris was Senior Vice President, Chief Financial Officer and Treasurer of International Coal Group, Inc. (a Northern and Central Appalachia and Illinois Basin coal producer) from September 2006 to June 2011. And before that, he was Executive Vice President and Chief Financial Officer of GMH Communities Trust from August 2004 to March 2006, Vice President and Chief Accounting Officer of Brandywine Realty Trust from September 1999 to March 2004 and Controller of Envirosource, Inc. from September 1996 to August 1999. Mr. Harris began his professional career with Ernst & Young LLP, where he was employed from September 1981 to July 1996 and served his last eight years there as an Audit Senior Manager. Mr. Harris earned a M.B.A. and a B.S. in Accounting from Lehigh University and is a certified public accountant.

Daniel M. Maher has served as Senior Vice President and Chief Legal Officer of our general partner since August 2010 and Secretary of our general partner since December 2010. Mr. Maher was a partner in the Columbus, Ohio office of the international law firm of Squire Sanders (US) LLP from March 1988 to December 2010 and prior thereto he was an associate and then partner with the predecessor firm to Squire Sanders from June 1972. He is a licensed attorney in Ohio with more than 40 years of experience in representing various clients in corporate, financial, merger and acquisition, contractual, real property, litigation and other legal matters. He received a J.D. from the University of Virginia and a B.S. from the United States Merchant Marine Academy.

Gregory J. Honish has served as Senior Vice President, Operations of our general partner since March 2009. Mr. Honish has served in other capacities with us and our predecessor since January 1999, including Vice President, Mining and Business Development from September 2007 to March 2009 and Senior Mining Engineer from January 1999 to September 2007. Mr. Honish has held various positions in engineering, operations and management in the coal industry during his 34-year professional career at mines in Northern Appalachia, Central Appalachia, the Illinois Basin and the Powder River Basin. Mr. Honish holds a B.S. in Mining Engineering from the University of Wisconsin. He is a licensed professional engineer in Ohio and West Virginia and a certified surface mine foreman in Ohio and Wyoming.

Michael B. Gardner has served as Vice President – Legal and General Counsel – Regulatory/Environmental of our general partner since June 2011, and as Assistant Secretary of our general partner since December 2010. Before that, Mr. Gardner served as General Counsel and Secretary of our general partner from September 2007 until December 2010. Prior to joining us, from June 2004 until May 2007, Mr. Gardner served as Associate General Counsel of Murray Energy Corporation, a privately owned coal mining company. Mr. Gardner is a licensed attorney in Ohio with more than 30 years of experience in the coal industry and in environmental regulatory compliance. Mr. Gardner serves on the Boards of Directors of the Ohio Coal Association and the Kentucky Coal Association. Mr. Gardner also serves as a trustee on the Energy and Mineral Law Foundation Governing Member Organization for the Ohio Coal Association and as Chairman of the Legal Committee of the Kentucky Coal Association. He is also a member of the American Corporate Counsel Association, Northeast Ohio Chapter, and the Cleveland Metropolitan Bar Association. Mr. Gardner received a J.D. from Case Western Reserve University, a M.B.A. from Ashland University and a B.S. in Environmental Biology from Ohio University.

Denise M. Maksimoski has served as Senior Director, Accounting (formerly Senior Director of Accounting) of our general partner since December 2009, and Director, Financial Reporting and General Accounting from August 2008 to December 2009. Prior to joining us, from 1997 to 2008, Ms. Maksimoski was with Deloitte & Touche, LLP in Washington, D.C. and Columbus, Ohio, most recently as an Audit Senior Manager from August 2005 to August 2008. Ms. Maksimoski earned a B.A. in Accounting, Actuarial Studies and Mathematics from Thiel College and is a certified public accountant.

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Brian D. Barlow was elected and has served as a member of the board of directors of our general partner in and since August 2007. Mr. Barlow has been a Managing Director of AIM since December 2011, and prior thereto was a Principal with AIM from January 2007 until December 2011. Prior to joining AIM, from August 2004 to August 2006, he was a Senior Securities Analyst for Scion Capital, a private investment partnership located in Cupertino, California. Mr. Barlow received an M.B.A. from Columbia Business School and a B.A. in Construction Sciences from the University of Washington.

Mr. Barlow’s over 20 years of investing experience, as well as his in-depth knowledge of the coal industry generally and our partnership in particular, provide him with the necessary skills to be a member of the board of directors of our general partner, a member of the Executive Committee and a member and the chairman of the Compensation Committee.

Matthew P. Carbone was elected and has served as a member of the board of directors of our general partner in and since August 2007. Mr. Carbone has been a Managing Director of AIM since he co-founded AIM in July 2006. Prior to co-founding AIM, Mr. Carbone was a Managing Director of MDC from January 2005 until July 2006. Prior to MDC, he led Wit Capital Group’s West Coast operations and worked in the investment banking divisions of Morgan Stanley, First Boston Corporation and Smith Barney. Mr. Carbone is a member of the board of directors of the general partner of Tunnel Hill Partners, an affiliate of AIM and C&T Coal. He received a M.B.A. from Harvard Business School and a B.A. in Neuroscience from Amherst College.

Mr. Carbone’s over 20 years of experience in corporate finance, as well as his in-depth knowledge of the coal industry generally and our partnership in particular, provide him with the necessary skills to be a member of the board of directors of our general partner.

Peter B. Lilly was elected and has served as a member of the board of directors of our general partner in and since June 2010. Since February 2009, he has been a part-time consultant relating to the coal industry international market and has also focused on investments in commercial real estate as a member through and as a member of his company, Harm Group, LLC. Before that, Mr. Lilly was an executive officer with CONSOL. Mr. Lilly joined CONSOL in October 2002 as Chief Operating Officer and served as President — Coal Group from February 2007 until his retirement in January 2009. Prior to joining CONSOL, Mr. Lilly served as President and Chief Executive Officer of Triton Coal Company LLC and Vulcan Coal Holdings LLC from 1998 to 2002. Between 1991 and 1998, Mr. Lilly was with Peabody Holding Company, Inc., where he served as President and Chief Operating Officer from 1995 to 1998, Executive Vice President from 1994 to 1995 and President of Eastern Associated Coal Corporation from 1991 to 1994. He is a former board member of the National Coal Association, the American Mining Congress and the World Coal Institute and a former chairman of the Safety Committee of the National Mining Association. Mr. Lilly earned a M.B.A. from Harvard Business School and a B.S. in General Engineering and Applied Science from the United States Military Academy at West Point, and served in the U.S. Army.

Mr. Lilly’s over 30 years of experience in the coal industry, much of it in executive management positions, provide him with the necessary skills to serve as a member of the board of directors of our general partner, the lead independent director, a member and the chairman of the Executive Committee, a member of the Audit Committee and a member of the Compensation Committee.

Robert J. Messey was elected and has served as a member of the board of directors of our general partner in and since October 2010. He has been an independent management consultant since April 2008. Before that, Mr. Messey served as Senior Vice President and Chief Financial Officer of Arch Coal, Inc. from December 2000 until April 2008. Prior to Arch Coal, he served as Chief Financial Officer of Sverdrup, a privately held engineering, architecture, construction and technology services firm, from 1993 until its acquisition in 1999 by Jacobs Engineering Group, Inc., a global firm providing the same services. After such acquisition, Mr. Messey served as Vice President of Financial Services with Jacobs until November 2000. Mr. Messey was with the public accounting firm of Ernst & Young LLP from 1968 to 1992, and served as a SEC Audit Partner from 1981 to 1992. He currently serves as a director, audit committee chairperson and compensation committee member on the board of Stereotaxis (NASDAQ:STXS). Mr. Messey also serves on the advisory board of Mississippi Lime Company, a non-public trust, and is chairperson of the audit committee and is a member of the compensation committee. Mr. Messey earned a B.S. in Business Administration from Washington University and is a certified public accountant.

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Mr. Messey has over 40 years of experience in accounting and finance, including 8 years as the Chief Financial Officer of a public company, 6 years as the Chief Financial Officer of a privately held company and 11 years as an SEC audit partner in a public accounting firm. His extensive accounting, financial and executive management experience, as well as his in-depth knowledge of the mining industry generally and our partnership in particular, provide him with the necessary skills to be a member of the board of directors of our general partner, a member of the Audit Committee and a member of the Compensation Committee. With respect to the Audit Committee, he also qualifies as an “audit committee financial expert.”

Gerald A. Tywoniuk was elected and has served as a member of the board of directors of our general partner in in and since January 2009. Mr. Tywoniuk also serves as a director of the general partner of American Midstream Partners, LP and as audit committee chairperson. In addition to his board of director roles, Mr. Tywoniuk has provided interim and project Chief Financial Officer services since May 2010. From June 2008 until August 2013, he held various management and finance roles, including Plan Representative, acting Chief Executive Officer, and Chief Financial Officer of Pacific Energy Resources Ltd., an oil production company. He previously served as Chief Financial Officer of Pacific Energy Partners, LP, an oil and refined products pipeline and storage partnership from 2002 to 2006, and MarkWest Energy Partners, L.P. and its predecessor, principally a natural gas and liquids midstream services partnership, from 1997 to 2002. Mr. Tywoniuk earned a Bachelor of Commerce degree from The University of Alberta, Canada, and is a Canadian chartered accountant.

Mr. Tywoniuk has over 31 years of experience in accounting and finance, including 12 years as the Chief Financial Officer of three public companies and 4 years as Vice President/Controller of a fourth public company. Mr. Tywoniuk’s extensive accounting, financial and executive management experience, as well as his in-depth knowledge of the mining industry generally and our partnership in particular, and his prior experience with publicly traded partnerships, provide him with the necessary skills to be a member of the board of directors of our general partner, a member of the Compensation Committee and a member and the chairman of the Audit Committee. With respect to the Audit Committee, he also qualifies as an “audit committee financial expert.”

Corporate Governance

The board of directors of our general partner has adopted corporate governance guidelines to assist it in the exercise of its responsibilities to provide effective governance over our affairs for the benefit of our unitholders. In addition, we have adopted a code of business conduct and ethics, which sets forth legal and ethical standards of conduct for all our officers, directors and employees. The corporate governance guidelines, the code of business conduct and ethics, the charters of our audit, compensation and executive committees and our lead independent director charter are available on our website at www.OxfordResources.com and in print without charge to any unitholder who requests any of them. A unitholder may make such a request in writing by mailing such request to Investor Relations, Oxford Resource Partners, LP, 41 South High Street, Suite 3450, Columbus, Ohio 43215, or by emailing such request to Investor Relations at ir@OxfordResources.com. Amendments to, or waivers from, the code of business conduct and ethics will also be available on our website and reported as may be required under SEC rules; however, any technical, administrative or other non-substantive amendments to the code of business conduct and ethics may not be posted. Please note that the preceding Internet address is for information purposes only and is not intended to be a hyperlink. Accordingly, no information found or provided at that Internet address or at our website in general is intended or deemed to be incorporated by reference herein.

Conflicts Committee

Our partnership agreement provides for the conflicts committee (the “Conflicts Committee”), as circumstances warrant, to review conflicts of interest between us and our general partner or between us and affiliates of our general partner. The Conflicts Committee, consisting solely of independent directors, determines if the resolution of a conflict of interest that has been presented is fair and reasonable to us. The members of the Conflicts Committee may not be executive officers or employees of our general partner or directors, executive officers or employees of its affiliates. In addition, the members of the Conflicts Committee must meet the independence and experience standards established by the NYSE and the Exchange Act. The composition of our Audit Committee qualifies it to be, and our Audit Committee presently serves as, our Conflicts Committee.

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Executive Committee

The board of directors of our general partner has established an executive committee (the “Executive Committee”). The Executive Committee handles matters that arise during the intervals between meetings of the board of directors and that, in the opinion of the chairman of the Executive Committee, do not warrant convening a special meeting of the board of directors but should not be postponed until the next scheduled meeting. Peter B. Lilly, Brian D. Barlow and Charles C. Ungurean serve as the members of the Executive Committee. Mr. Lilly serves as the chairman of the Executive Committee.

Audit Committee

The board of directors of our general partner has established an audit committee (the “Audit Committee”) that complies with the NYSE requirements and Section 3(a)(58)(A) of the Exchange Act. Our general partner is generally required to have at least three independent directors serving on its board at all times. Gerald A. Tywoniuk, Peter B. Lilly and Robert J. Messey are our independent directors and serve as the members of the Audit Committee. The board has determined that Mr. Tywoniuk, who serves as the chairman of the Audit Committee, and also Mr. Messey, each have such accounting or related financial management expertise sufficient to qualify him as an audit committee financial expert in accordance with Item 401 of Regulation S-K.

The Audit Committee meets on a regularly-scheduled basis and with our independent accountants at least four times each year. The Audit Committee has the authority and responsibility to review our external financial reporting, to review our procedures for internal auditing, to review the adequacy of our internal accounting controls, to consider the qualifications and independence of our independent accountants, to engage and resolve disputes with our independent accountants, including the letter of engagement and statement of fees relating to the scope of the annual audit work and any special audit work that may be recommended or required by the independent accountants, and to engage the services of any other advisors and accountants as the Audit Committee deems advisable. The Audit Committee reviews and discusses the audited financial statements with management, discusses with our independent auditors matters required to be discussed by SAS 114 - Communications with Audit Committees, and makes recommendations to the board of directors of our general partner regarding the inclusion of our audited financial statements in this Annual Report on Form 10-K.

Compensation Committee

The board of directors of our general partner has established a compensation committee (the “Compensation Committee”). The Compensation Committee establishes standards and makes recommendations concerning the compensation of our officers and directors. In addition, the Compensation Committee determines and establishes the standards for any awards to our officers and other employees, including the performance standards or other restrictions pertaining to the vesting of any such awards, under our long-term incentive plan. Brian D. Barlow, Peter B. Lilly, Robert J. Messey and Gerald A. Tywoniuk serve as the members of the Compensation Committee. Mr. Barlow serves as the chairman of the Compensation Committee.

Meeting of Non-Management Directors and Communications with Directors

At least quarterly during a meeting of the board of directors of our general partner, all of our independent directors meet in an executive session without management participation or participation by non-independent directors. Mr. Lilly, the lead independent director, presides over these executive sessions.

The board of directors of our general partner welcomes questions or comments about us and our operations. Unitholders or interested parties may contact the board of directors, including any individual director, by contacting the Secretary of our general partner at dmaher@OxfordResources.com, by fax at 614-754-7100 or at the following address: Name of the Director(s), c/o Secretary, Oxford Resource Partners, LP, 41 South High Street, Suite 3450, Columbus, Ohio 43215.

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Section 16(a) Beneficial Ownership Reporting Compliance

Section 16(a) of the Exchange Act requires the board of directors and executive officers of our general partner, and persons who own more than 10 percent of a registered class of our equity securities, to file with the SEC and any exchange or other system on which such securities are traded or quoted initial reports of ownership and reports of changes in ownership of our common units and other equity securities. Officers, directors and greater than 10 percent unitholders are required by the SEC’s regulations to furnish to us and any exchange or other system on which such securities are traded or quoted with copies of all Section 16(a) forms they filed with the SEC. To our knowledge, based solely on a review of the copies of such reports furnished to us and written representations that no other reports were required, we believe that all reporting obligations of the officers, directors and greater than 10 percent unitholders of our general partner under Section 16(a) were satisfied during the year ended December 31, 2013.

Item 11.          Executive Compensation

Compensation Discussion and Analysis

The following is a discussion of the compensation policies and decisions of the board of directors of our general partner (the “Board”) and the Compensation Committee for the year ended December 31, 2013 with respect to the following individuals, who were executive officers of our general partner and referred to as the “named executive officers”:

● Charles C. Ungurean, President and Chief Executive Officer;

● Bradley W. Harris, Senior Vice President, Chief Financial Officer and Treasurer;

● Daniel M. Maher, Senior Vice President, Chief Legal Officer and Secretary;

● Gregory J. Honish, Senior Vice President, Operations; and

● Michael B. Gardner, Vice President – Legal, General Counsel - Regulatory/Environmental and Assistant Secretary

Our compensation program is designed to recruit and retain as executive officers individuals with the highest capacity to develop, grow and manage our business, and to align their compensation with our short-term and long-term goals. To do this, our compensation program for executive officers is generally made up of the following components: (i) base salary, designed to compensate our executive officers for work performed during the fiscal year; (ii) short-term incentive programs, designed to reward our executive officers for our financial and safety performances and for their individual performances during the fiscal year; and (iii) equity-based awards granted under our LTIP, which are meant to align our executive officers’ interests with those of our unitholders and our long-term performance.

Role of the Board, the Compensation Committee and Management

Our general partner, under the direction of the Board, is responsible for the management of our operations and employs all of the employees that operate our business. These responsibilities include establishing and maintaining the policies and practices with respect to executive compensation. The Board appoints and maintains the Compensation Committee to help the Board administer certain aspects of the compensation policies and programs for our executive officers and certain other employees and to make recommendations to the Board relating to the compensation of the directors and executive officers of our general partner. The compensation programs for our executive officers consist generally of base salaries, annual incentive bonuses and awards under our LTIP, in the form of equity-based phantom units, as well as other customary employment benefits.

The Compensation Committee and the Board are charged with, among other things, the responsibility of:

● reviewing executive officer compensation policies and practices to ensure adherence to our compensation philosophies and that the total compensation paid to our executive officers is fair, reasonable and competitive;

● reviewing base salary levels for our executive officers and determining any adjustments thereto;

● assessing the individual performance of our executive officers and their contributions to our company-wide performance;

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● determining the annual bonuses to be provided to our executive officers for a given year after taking into account target bonus levels set forth in executive officers’ employment agreements or otherwise established for the year; and

● determining the types, amounts and vesting terms of awards to be provided to our executive officers under our LTIP.

In making compensation determinations, the Compensation Committee and the Board consider the recommendations of our Chief Executive Officer with respect to the other executive officers. The total compensation of our executive officers and the components and relative emphasis among components of their annual compensation are reviewed on at least an annual basis by the Compensation Committee with any proposed changes recommended to the Board for final approval.

Compensation Objectives and Methodology

The principal objective of our executive compensation program is to attract and retain individuals of demonstrated competence, experience and leadership who share our business aspirations, values, ethics and culture. A further objective is to provide incentives to and reward our executive officers and other key employees for positive contributions to our business and operations, and to align their interests with our unitholders’ interests.

In setting our compensation programs, we consider the following objectives:

● to create unitholder value through achievement of relevant financial performance goals;

● to provide a significant percentage of total compensation that is “at-risk” or variable;

● to encourage significant equity holdings to align the interests of executive officers and other key employees with those of unitholders;

● to provide competitive, performance-based compensation programs that allow us to attract and retain superior talent; and

● to develop a strong correlation between business performance, safety, environmental stewardship and cooperation on the one hand and executive compensation on the other hand.

Taking account of the foregoing objectives, we structured total 2013 compensation for our executives to provide a guaranteed amount of cash compensation in the form of competitive base salaries, while also providing a meaningful amount of annual cash compensation dependent on our performance and individual performance of the executives, in the form of annual bonuses. We also sought to provide a portion of total compensation in the form of equity-based awards under our LTIP, in order to align the interests of executives and other key employees with those of our unitholders and for retention purposes. In both January 2013 and January 2014, but relating in each case to performance in the immediately preceding year, we made, and in the future we expect to regularly make, equity-based awards as a part of our annual compensation decision-making process.

Compensation decisions for individual executive officers were the result of the subjective analysis of a number of factors, including the individual executive officer’s experience, skills or tenure with us, changes to the individual executive officer’s position and responsibilities, and our performance. In measuring the contributions of executive officers and our performance, a variety of financial measures were considered, including non-GAAP financial measures used by management to assess our financial performance. For 2013, the Board used an EBITDA-based measure as the primary measure of our operating performance. In addition, our safety performance and an evaluation of the individual performance of each of the executive officers was taken into consideration.

In making individual compensation decisions, the Compensation Committee and the Board relied on and will continue to rely on performance goals or targets for a significant part of the incentive compensation bonuses of our executive officers. Each executive officer’s current and prior compensation was considered in setting compensation for 2013. The amount of each executive officer’s current compensation was considered as a base against which determinations were made as to whether increases were appropriate to retain the executive officer in light of competition or in order to provide continuing performance incentives. The Compensation Committee and the Board retain and exercise their discretion to adjust the components of compensation to achieve our goal of recruiting, promoting and retaining executive officers with the skills necessary to execute our business strategy and develop, grow and manage our business.

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For each of the 2013 and 2014 performance periods, our Compensation Committee made and intends to make compensation recommendations to the Board based upon trends occurring within our industry, including from a peer group of companies that our Compensation Committee identifies and reviews on at least an annual basis. The peer group of companies utilized and to be utilized in both 2013 and 2014 consist of Alliance Resource Partners, L.P., Alpha Natural Resources, Cloud Peak Energy, Hallador Energy Company, James River Coal Company, LRR Energy, LP, Natural Resource Partners, L.P., Patriot Coal Corporation, Rhino Resource Partners, L.P., Walter Energy, Inc. and Westmoreland Coal Company.

Elements of the Compensation Programs

Overall, our executive officer compensation programs are designed to be consistent with the philosophy and objectives set forth above. The principal elements of our executive officer compensation programs are summarized in the table below, followed by a more detailed discussion of each compensation element.

Element	Characteristics	Purpose
Base Salaries	Fixed annual cash compensation in the form of base salaries. Base salaries of comparable positions within our peer group of companies is taken into account. Our executive officers are eligible for periodic increases in base salary. Increases may be based on performance or such other factors as the Board or the Compensation Committee may determine.	Keep our fixed annual compensation competitive with the market for skills and experience necessary to execute our business strategy.
Annual Incentive Bonuses	Performance-related annual cash incentives earned based on company objectives and individual performance of the executive officers. Trends for our peer group are taken into account in setting annual cash incentive awards.	Align annual compensation with our financial and safety performances and reward our executive officers for individual performance during the year. Amounts provided as incentive bonuses are also designed to provide competitive total direct cash compensation; potential for awards above or below target amounts are intended to motivate our executive officers to achieve greater levels of performance.
Equity-Based Awards (phantom-units)	Equity-based awards granted at the discretion of the Board. Awards are based on our performance and on competitive practices at peer companies. For 2013 and 2014, we made and intend to make award grants to the executive officers having a unit value at the time of grant equal to their base salary (50% of his base salary for Mr. Gardner), with 50% (100% in the case of Mr. Gardner) thereof to vest ratably over four years and the other 50%  (for all except Mr. Gardner) to vest based on the achievement of performance criteria established in connection with the award. Awards will be settled upon vesting with either a net cash payment or an issuance of common units, at the discretion of the Board.	Align interests of our executive officers with unitholders and motivate and reward our executive officers to increase unitholder value over the long term. For the executive officers, a combination of ratable vesting in four annual installments for 50% of the award and vesting based on performance criteria for the other 50% of the award is designed to facilitate retention of our executive officers and to achieve greater levels of performance.

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Element	Characteristics	Purpose
Retirement Plan	Discretionary qualified 401(k) retirement plan benefits are available for our executive officers.	Provide our executive officers with the opportunity to save for their future retirement.
Health and Welfare Benefits	Health and welfare benefits (medical, dental, vision, disability insurance and life insurance) are available for our executive officers.	Provide benefits to meet the health and wellness needs of our executive officers and their families.

Base Salaries

Design.  Base salaries for our executive officers are determined annually by an assessment of our overall financial and operating performance, each executive officer’s personal performance and changes in executive officer responsibilities. While many aspects of performance can be measured in financial terms, senior management is also evaluated in areas of performance that are more subjective. These areas include the development and execution of strategic plans, the exercise of leadership in the development of management and other employees, innovation and improvement in our business activities and each executive officer’s involvement in industry groups and in the communities that we serve. We seek to compensate executive officers for their performance throughout the year with annual base salaries that are fair and competitive within our marketplace and which ensure the attraction, development and retention of superior talent. We believe that executive officer base salaries should be competitive with salaries for executive officers in similar positions and with similar responsibilities in our marketplace, adjusted for financial and operating performance, and each executive officer’s personal performance, length of service with us and previous work experience. For 2013 and 2014, base salary determinations focused and will continue to focus on the above considerations and also were made and will be made based upon relevant market data, including data from our peer group.

Base salaries are reviewed annually to ensure continuing consistency with market levels and our level of financial performance during the prior year. Future adjustments to base salaries and salary ranges will reflect average movement in the competitive market as well as individual performance. Annual base salary adjustments, if any, for the Chief Executive Officer are approved by the Non-employee Directors based upon recommendations from the Compensation Committee. Annual base salary adjustments, if any, for the other executive officers are approved by the Board based upon recommendations from the Compensation Committee, which recommendations may take into account input from the Chief Executive Officer.

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Actions Taken With Respect to Base Salaries.  There were no base salary increases for the executive officers for 2013. Given the fact that the base salaries for a number of the executive officers had been unchanged for three or more years, the Compensation Committee and the Board gave serious consideration to and ultimately determined to make some increases in the base salaries for 2014. The Compensation Committee and the Board have considered the salary levels of comparable executive officers in our peer group, and have used those salary levels as a check against their conclusions regarding salaries for our executive officers, but the base salaries for 2013 and 2014 have not been benchmarked at any particular level relative to our peer group. The base salaries of the executive officers for 2013 and 2014 are reflected in the table below.

Name	2013 Base Salary(1)		2014 Base Salary(2)
Charles C. Ungurean	$	500,000	$	500,000
Bradley W. Harris		300,000		315,000
Daniel M. Maher		270,000		297,000
Gregory J. Honish		210,000		220,500
Michael B. Gardner		170,000		178,500

(1) There were no changes in base salaries at the start of or during 2013.

(2) Mr. Ungurean elected not to seek and thus did not recommend or receive a salary increase for himself.

Bonuses

Annual Incentive Bonuses.  As one way of accomplishing compensation objectives, our executive officers are rewarded for their contribution to our financial and operational success through the award of annual cash incentive bonuses. Annual incentive bonuses, if any, for the Chief Executive Officer are approved by the Non-employee Directors based upon recommendations from the Compensation Committee. Annual incentive bonuses, if any, for the other executive officers are approved by the Board based upon recommendations from the Compensation Committee, which recommendations may take into account input from the Chief Executive Officer (and the Chief Legal Officer in the case of Mr. Gardner).

For our executive officers, target amounts for the annual incentive bonuses are set forth in their employment agreements, which are discussed in more detail under “Employment and Severance Arrangements” below. The employment agreements for the executive officers provide for their eligibility to receive annual incentive bonuses based on target amounts of a specified percentage of their annual base salaries, or such other greater percentage as may be approved by the Non-employee Directors (in the case of our CEO, Charles C. Ungurean) or the Board (in the case of our other executive officers), in any such case based on the recommendations of the Compensation Committee, which recommendations in the case of the other executive officers may take into account input from the CEO (and the Chief Legal Officer in the case of Mr. Gardner). The target bonus amounts, as a percentage of annual base salaries, were and are, for both 2013 and 2014, 125% for Mr. Ungurean, 100% for Messrs. Harris, Maher and Honish and 50% for Mr. Gardner.

The annual incentive bonus award for each executive officer is contingent on the executive officer’s continued employment with our general partner at the time of the award. Annual incentive bonuses for both 2013 and 2014 are based on a prescribed formula, which includes a portion to be determined on a discretionary basis based on a subjective evaluation referencing personal performance criteria. The Board and the Compensation Committee believe that this approach to assessing performance for annual incentive bonus purposes results in the most appropriate bonus decisions. The Board and the Compensation Committee (or the Chief Legal Officer in the case of Mr. Gardner) established the following factors and weighting thereof for the annual incentive bonus formula for both 2013 and 2014:

● the level of achievement of certain financial performance goals for the year (our budgeted Adjusted EBITDA less maintenance and mine development capital expenditures for the year), with a weighting as a percentage of the target bonus amounts at the target level for such factor of 50% (35% for Mr. Gardner) for both 2013 and 2014;

● the level of achievement of established safety criteria for the year, with a weighting as a percentage of the target bonus amounts at the target level for such factor of 15% for both 2013 and 2014; and

● the discretionary bonus amount determined based on personal performance criteria, with a weighting as a percentage of the target bonus amounts of 35% (50% for Mr. Gardner) for both 2013 and 2014.

In applying the first two, non-discretionary factors, there are minimum levels below which there is no award for the factor, as well as target levels at which the target bonus amount for the factor is awarded and maximum levels at which there are awards of up to 200% of the target bonus amount for the factor. There are also incremental increases in the bonus awards between the minimum and target levels and also the target and maximum levels. These factors utilized for bonus decisions are considered to be the most appropriate measures upon which to base the annual incentive cash bonus decisions as the Compensation Committee and our Board believe that they help to align individual compensation with competency and contribution and that they most directly correlate to increases in long-term value for our unitholders.

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Based on these factors, the Board (in the case of everyone except the CEO and Mr. Gardner), the Non-employee Directors (in the case of the CEO) and the Chief Legal Officer (in the case of Mr. Gardner) determined to award the incentive bonus amounts set forth in the table below to our executive officers for performance in 2013.

Name	Financial Performance(1)		Safety(2)		Personal Performance(3)		Total
Charles C. Ungurean(4)	$	304,400	$	93,750	$	218,750	$	616,900
Bradley W. Harris(5)		146,100		45,000		105,000		296,100
Daniel M. Maher(5)		131,500		40,500		94,500		266,500
Gregory J. Honish(5)		102,300		31,500		73,500		207,300
Michael B. Gardner(6)		28,950		12,750		42,500		84,200

(1) The Company’s financial performance was at 99.0% of the target level, resulting in awards for the financial performance component at 97.4% of the target level.

(2) Safety is considered of paramount importance to the Company, and the Company is very pleased with the strong safety performance for 2013. While this performance resulted in achievement in excess of the target level of achievement for the safety component, the Committee based on management’s recommendation determined for 2013 to limit the awards for the safety component to the target level.

(3) All of the executive officers were determined to have met their target levels of personal performance and accordingly were awarded amounts relating to personal performance at their target levels for that factor.

(4) The annual incentive bonus award for Mr. Ungurean represented 123.4% of his base salary and 98.7% of his target bonus amount.

(5) The annual incentive bonus awards for each of Messrs. Harris, Maher and Honish represented 98.7% of his base salary and also 98.7% of his target bonus amount.

(6) The annual incentive bonus award for Mr. Gardner represented 49.5% of his base salary and 99.1% of his target bonus amount.

Retention Bonuses.  Messrs. Harris, Maher and Honish were and are each eligible for retention bonuses in the aggregate amount of their base salaries in effect for 2013, payable one-third upon completion of a satisfactory refinancing of the Company’s credit facility and two-thirds upon completion of continued employment through December 31, 2014, while Mr. Gardner was eligible for a retention bonus of $50,000 payable for and subject to his continued employment through May 15, 2013. Due to the refinancing of the Company’s credit facility during 2013, and Mr. Gardner’s continued employment through the required date, retention bonuses were paid to Messrs. Harris, Maher, Honish and Gardner in 2013 in the amounts set forth in the table below. The purpose of the retention bonuses was and is to improve the chances of our general partner retaining the services of these executive officers, which retentions the Compensation Committee and the Board have determined to be important for us.

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Name	2013 Retention Bonus
Bradley W. Harris	$	100,000
Daniel M. Maher		90,000
Gregory J. Honish		70,000
Michael B. Gardner		50,000

Total Bonuses for 2013.  Including the annual cash incentive bonuses and the retention bonuses for 2013 described in the tables above, our executive officers received total bonuses for 2013 in the amounts set forth in the table below.

Name	Incentive Bonus		Retention Bonus		Total Bonus
Charles C. Ungurean	$	616,900	$	-	$	616,900
Bradley W. Harris		296,100		100,000		396,100
Daniel M. Maher		266,500		90,000		356,500
Gregory J. Honish		207,300		70,000		277,300
Michael B. Gardner		84,200		50,000		134,200

Equity-Based Awards

Design.  Our LTIP was originally adopted in 2007 in connection with our formation and subsequently amended and restated in July 2010 in connection with our initial public offering. In adopting our LTIP, the Board recognized that it needed a source of equity to attract new members to and retain existing members of the management team, as well as to provide an equity incentive to other key employees.

Our LTIP is designed to encourage responsible and profitable growth, while taking into account non-routine factors that may be integral to our success. In addition to recruiting and retaining grantees, equity-based grants are used to incentivize performance that leads to enhanced unitholder value and closely align the interests of executive officers and key employees with those of our unitholders. Equity-based grants provide a vital link between the long-term results achieved for our unitholders and the rewards provided to executive officers and other key employees.

An amendment to our LTIP was adopted effective December 31, 2013, increasing the number of our common units authorized under our LTIP.

Phantom Units.  The only awards made under our LTIP since its adoption have been phantom units. A phantom unit is a notional unit that entitles the holder to receive an amount of cash equal to the fair market value of one common unit upon vesting of the phantom unit, unless the Board elects to pay such vested phantom unit with a common unit in lieu of cash. Historically, including in 2013, we have always issued common units in lieu of cash. Unvested phantom units are forfeited at the time the holder terminates employment, except for a termination due to death or disability, which results in vesting acceleration. For phantom units awarded to executive officers under our LTIP for performance in years through 2010, the phantom units generally vest as to 25% of the award on the initial vesting date established at the time of the award and on each of the first three anniversaries of that initial vesting date. For phantom units awarded to executive officers (except Mr. Gardner) under our LTIP for performance in 2011 and thereafter, 50% of the awarded phantom units vest generally on the same basis as before and the remaining 50% of the phantom units vest based on and upon achievement of specified performance criteria. For Mr. Gardner, all of the phantom units awarded to him vest on the same basis as before. All LTIP awards for our executive officers vest in full upon a change in control of us or our general partner.

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Equity-Based Award Policies.  Prior to 2010, equity-based awards were granted by the Board and were limited to the grants at our formation in 2007 (or for executives who joined us after our formation, upon or in connection with their commencement of employment) and grants that were made in certain limited circumstances to reward individual service and performance. In early 2010, the Board delegated a portion of its duties and responsibilities under our LTIP to the Compensation Committee with the directive that equity-based awards are to be awarded more regularly as part of the ongoing total annual compensation package for executive officers, rather than only in such discrete circumstances. Annual equity compensation grants, if any, for the CEO are approved by the Non-employee Directors based upon recommendations from the Compensation Committee. Annual equity compensation grants for the other executive officers are approved by the Board based upon recommendations from the Compensation Committee, which recommendations may take into account input from the CEO.

Equity-Based Awards for 2013.  In keeping with its prior determination to make regular equity-based awards to our named executive officers as part of their annual compensation package, the Board approved awards of phantom units which were granted to the named executive officers on January 1, 2014 in the amounts set forth in the table below. These awards, although granted in 2014, were intended as a part of the named executive officers’ 2013 compensation and were granted to reward the named executive officers for performance in 2013. The Board determined the amount of the awards such that the phantom unit awards represent a total of 100% (50% for Mr. Gardner) of each grantee’s base salary for 2013, with 50% (100% for Mr. Gardner) thereof to vest ratably over four years and the other 50% (for all grantees except Mr. Gardner) thereof to vest based on the achievement of criteria relating to our financial performance (based on Adjusted EBITDA less maintenance and mine development capital expenditures).

Name	Value of Phantom Units(1)		Number of Phantom Units
Charles C. Ungurean	$	500,000		406,504
Bradley W. Harris		300,002		243,904
Daniel M. Maher		270,000		219,512
Gregory J. Honish		210,003		170,734
Michael B. Gardner		85,003		69,108

(1) The number of phantom units was determined based on the closing trading price of our common units on December 31, 2013, so that the number of phantom units corresponding to the number of our common units having a value equal to the awarded dollar amount on the award date were granted.

Deferred Compensation

Tax-deferred retirement plans are a common way that companies assist employees in preparing for retirement. We provide our eligible executive officers and other employees with an opportunity to participate in our 401(k) plan. The plan allows executive officers and other employees to contribute compensation for retirement up to Internal Revenue Service imposed limits, either on a tax deferred or after-tax basis. The 401(k) plan permits us to make annual discretionary contributions to the plan as a percentage of the eligible compensation of participants in the plan. Committed annual contributions of 3% or more of such eligible compensation will maintain “safe harbor” tax-qualified status for the plan. For 2012, we committed to make an employer discretionary contribution of 4% of such eligible compensation. We did not make such a commitment for 2013 and no contribution is being made to the 401(k) plan for 2013. Decisions regarding this element of compensation do not impact any other element of compensation.

Perquisites and Other Benefits

Although perquisites are not a significant factor in our compensation programs, we provide certain limited perquisite and personal benefits to certain of the named executive officers, including the use primarily for business purposes (with personal usage being limited to usage for commuting purposes) of a company-owned automobile for Mr Ungurean. We provide these benefits to assist the executive officers in performing their services for us and they are not factored into the Board’s determinations with respect to other elements of total compensation.

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Recoupment Policy

We currently do not have a formal compensation recoupment policy applicable to annual incentive bonuses, equity awards or other compensation. The Compensation Committee has reviewed and is anticipating legislative and regulatory developments with respect to such a policy and intends to adopt such a policy consistent with applicable legal and regulatory requirements and securities exchange listing standards, as well as economic and market conditions.

Employment and Severance Arrangements

The Board and the Compensation Committee consider the maintenance of a sound management team to be essential to protecting and enhancing our best interests. To that end, we recognize that the uncertainty that may exist among management with respect to their “at-will” employment with our general partner may result in the departure or distraction of management personnel to our detriment. Accordingly, our general partner has employment agreements with our executive officers. For each of our named executive officers, the current terms of these employment agreements run through December 31, 2015 or later in the case of Mr. Ungurean. There are annual renewals of each of the employment agreements after their specified terms unless terminated by either party with notice at least 90 days prior to any such renewal. These employment agreements provide for the base salary and target bonus amounts for each executive officer and contain severance arrangements that we believe are appropriate to encourage the continued attention and dedication of members of our management. The employment agreements with our executive officers are described more fully below under “— Potential Payment Upon Termination or Change in Control — Employment Agreements with Named Executive Officers.”

Compensation Committee Report

We have reviewed and discussed with management certain compensation discussion and analysis provisions to be included in this Annual Report on Form 10-K for the year ended December 31, 2013 to be filed pursuant to Section 13(a) of the Securities and Exchange Act of 1934, or this Annual Report on Form 10-K. Based on that review and discussion, we recommend to the Board that the compensation discussion and analysis provisions be included in this Annual Report on Form 10-K.

Compensation Committee
Brian D. Barlow, Chairman
Peter B. Lilly
Robert J. Messey
Gerald A. Tywoniuk

Risk Assessment in Compensation Programs

Management of our general partner, with the support of our human resources, finance and legal departments, has assisted our Compensation Committee and our Board in analyzing the potential risks arising from our compensation policies and practices, and our Compensation Committee and our Board have determined that there are no such risks that are reasonably likely to have a material adverse effect on us.

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Summary Compensation Table

The following table sets forth certain information with respect to the compensation paid to the named executive officers for the periods indicated.

Name and Principal Position	Year	Salary ($)		Bonus ($)(1)		Unit Awards ($)(2)		All Other Compensation ($)(3)		Total ($)
Charles C. Ungurean	2013	$	501,923	$	616,900	$	500,000	$	3,984	$	1,622,807
President and Chief Executive Officer	2012		511,155		275,000		526,688		13,835		1,326,678
	2011		511,155		104,895		92,227		13,541		720,873
Bradley W. Harris	2013		301,154		396,100		300,002		8,960		1,006,216
Senior Vice President, Chief Financial Officer and	2012		108,642		162,500		908,000		3,090		1,182,052
Treasurer	2011		-		-		-		-		-
Daniel M. Maher	2013		271,039		390,250		270,000		9,269		940,558
Senior Vice President, Chief Legal Officer and Secretary	2012		277,847		135,000		270,038		19,069		701,954
	2011		265,846		201,250		448,463		15,332		930,890
Gregory J. Honish	2013		210,808		277,300		210,003		283		698,394
Senior Vice President, Operations	2012		220,040		102,500		210,054		10,083		542,677
	2011		214,851		33,075		80,851		10,083		338,860
Michael B. Gardner	2013		170,654		134,200		85,003		10,683		400,540
Vice President – Legal, General Counsel –	2012		186,144		68,000		82,545		17,683		354,372
Regulatory/Environmental and Assistant Secretary	2011		174,774		74,250		27,502		6,792		283,318

(1) The 2013 bonus amounts for each named executive officer include incentive bonus amounts ($616,900 for Mr. Ungurean, $296,100 for Mr. Harris, $266,500 for Mr. Maher, $207,300 for Mr. Honish, and $84,200 for Mr. Gardner). These incentive bonus amounts represent discretionary annual cash awards accrued with respect to 2013, and will be paid to all of the named executive officers in March 2014 except that the incentive bonus amount for Mr. Gardner was and will be paid partly in December 2013 and the remainder in March 2014. The 2013 bonus amounts for each named executive officer except Mr. Ungurean also include retention bonus amounts ($100,000 for Mr. Harris, $90,000 for Mr. Maher, $70,000 for Mr. Honish, and $50,000 for Mr. Gardner). The 2013 bonus amount for Mr. Maher additionally included a remaining employment inducement bonus amount of $33,750 paid in early 2013.

(2) Except for Mr. Harris, 2012 amounts shown reflect the grant date fair value of phantom units awarded under the LTIP to each of them in January and March 2013 for each of the named executive officers except Mr. Gardner and in January 2013 only for Mr. Gardner, all relating to services provided in 2012. For Mr. Harris, 2012 amounts shown reflect the grant date fair value of phantom units awarded to him under the LTIP in connection with his employment in August 2012. For each named executive officer, the 2013 amount shown reflects the grant date fair value of phantom units awarded under the LTIP to each of them in January 2014 relating to services provided in 2013.

(3) For named executive officers, the 2013 amounts shown include payments made in 2013 with respect to life insurance benefits provided to each of the named executive officers, a holiday-related allowance paid in 2013 to each of the named executive officers, the taxable portion of automobile allowances paid to Messrs. Harris, Maher and Gardner, and the dues paid for Messrs. Ungurean, Harris and Maher for a dining and athletic club facility located in the same building as our executive offices.  Also for Mr. Ungurean, who is provided a company-owned automobile primarily for business use (with personal use being limited to usage for commuting purposes), the amount shown for 2013 also includes the cost to us of providing the automobile to him for his use for the estimated personal usage portion thereof for commuting purposes (10% of the total cost) in the amount of $1,966.

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Grants of Equity-Based Awards for 2013

The following table provides information regarding grants of equity-based awards to named executive officers for services during the year ended December 31, 2013.

Name	Grant Date	All Other Unit Awards: Number of Units (#)		Grant Date Fair Value of Unit Awards ($)(1)
Charles C. Ungurean	1/1/14		406,504		500,000
President and Chief Executive Officer
Bradley W. Harris	1/1/14		243,904		300,002
Senior Vice President, Chief Financial Officer and Treasurer
Daniel M. Maher	1/1/14		219,512		270,000
Senior Vice President, Chief Legal Officer and Secretary
Gregory J. Honish	1/1/14		170,734		210,003
Senior Vice President, Operations
Michael B. Gardner	1/1/14		69,108		85,003
Vice President-Legal, General Counsel-Regulatory/Environmental and Assistant Secretary

(1) Amounts shown are based on the grant date fair market value of our common units of $1.23 for units granted effective January 1, 2014 with respect to services provided by the executive officers during 2013.

Outstanding Equity-Based Awards at December 31, 2013

The following table provides information regarding outstanding equity-based awards held by the named executive officers as of December 31, 2013.  All such equity-based awards consist of phantom units granted under our LTIP, other than the Class B units in our general partner held by Mr. Maher.  None of the named executive officers hold outstanding option awards.

	Unit Awards
Name	Number of Phantom Units That Have Not Vested (#)(1)		Number of Class B Units That Have Not Vested (#)(2)		Market Value of Units That Have Not Vested ($)(3)
Charles C. Ungurean		160,077				196,895
President and Chief Executive Officer
Bradley W. Harris		117,878				144,990
Senior Vice President, Chief Financial Officer and Treasurer
Daniel M. Maher		88,807				109,233
Senior Vice President, Chief Legal Officer and Secretary				3.1720195		1,234
Gregory J. Honish		67,540				83,074
Senior Vice President, Operations
Michael B. Gardner		23,915				29,415
Vice President – Legal, General Counsel – Regulatory/Environmental and Assistant Secretary

(1) The phantom unit numbers do not include awards relating to services provided in 2013 that were effective January 1, 2014. As to Messrs. Ungurean and Honish, a portion of the units (1,893 for Mr. Ungurean and 1,659 for Mr. Honish) vest in equal amounts on each of March 31, 2014 and the next anniversary thereof, an additional portion of the units (13,806 for Mr. Ungurean and 5,241 for Mr. Honish) vest in equal amounts on each of March 31, 2014 and the next two anniversaries thereof, a further portion of the units (56,564 for Mr. Ungurean and 23,756 for Mr. Honish) vest in equal amounts on each of March 31, 2014 and the next three anniversaries thereof, and the remainder of the units (87,814 for Mr. Charles Ungurean and 36,884 for Mr. Honish) vest in two stages based upon achievement of certain performance criteria.  As to Mr. Harris, 50,000 of his units vest in equal amounts on each of March 31, 2014 and the next anniversary thereof, 33,940 of his units vest on March 31, 2014 and the next three anniversaries thereof, and the remaining 33,938 of his units vest in two stages based upon achievement of certain performance criteria.  As to Mr. Maher, 4,105 of his units vest on January 1, 2014, 6,738 of his units vest in equal amounts on March 31, 2014 and the next two anniversaries thereof, 30,544 of his units vest in equal amounts on each of March 31, 2014 and the next three anniversaries thereof, and the remaining 47,420 of his units vest in two stages based upon achievement of certain performance criteria.  As to Mr. Gardner, 564 of his units vest in equal amounts on each of March 31, 2014 and the next anniversary thereof, 4,119 of his units vest in equal amounts on each of March 31, 2014 and the next two anniversaries thereof, and the remaining 19,232 of his units vest in equal amounts on each of March 31, 2014 and the next three anniversaries thereof.

(2) Amounts shown are the number of unvested Class B units of our general partner granted to Mr. Maher.  These units vest in equal amounts on January 1, 2014 and the next anniversary thereof.

(3) For phantom units, based on the closing price of our common units of $1.23 on December 31, 2013; for Class B units, reflects an estimate of the fair market value of the Class B units of our general partner as of December 31, 2013, as determined in accordance with FASB ASC Topic 718.

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In addition to these outstanding equity-based awards at December 31, 2013, there were additional equity-based awards on January 1, 2014 as described above under “Equity-Based Awards – Equity-Based Awards for 2013.”

Units Vested in 2013

The following table shows the phantom unit awards and awards of Class B units of our general partner that vested in our named executive officers during 2013.  None of the named executive officers held or exercised any options in 2013.

Name	Number of Units Acquired on Vesting (#)			Value Realized on Vesting ($)
Charles C. Ungurean		5,548	(1)	$	15,257	(1)
President and Chief Executive Officer
Bradley W. Harris		25,000	(1)		68,750	(1)
Senior Vice President, Chief Financial Officer and Treasurer
Daniel M. Maher		6,351	(2)		24,322	(2)
Senior Vice President, Chief Legal Officer and Secretary		1.586010	(3)		2,218	(3)
Gregory J. Honish		2,577	(1)		7,087	(1)
Senior Vice President, Operations
Michael B. Gardner		1,655	(1)		4,551	(1)
Vice President – Legal, General Counsel – Regulatory Environmental and Assistant Secretary

(1) These units vested on March 31, 2013, and the value realized amount reflects a unit value of $2.75 per unit on such vesting date.

(2) Of these units, 4,105 units vested on January 1, 2013 and 2,246 units vested on March 31, 2013, and the value realized amount reflects a unit value of $4.42 and $2.75 per unit, respectively, on each such vesting date.

(3) These units vested on January 1, 2013, and the value realized amount reflects an estimate of the fair market value of such units as of such date, as determined in accordance with FASB ASC Topic 718.

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Pension Benefits

The named executive officers do not participate in any defined benefit pension plans and received no pension benefits during the year ended December 31, 2013.

Nonqualified Deferred Compensation

The named executive officers do not participate in any nonqualified deferred compensation plans and received no nonqualified deferred compensation during the year ended December 31, 2013.

Potential Payment Upon Termination or Change in Control

Employment Agreements with Named Executive Officers

Our general partner has employment agreements with each of our named executive officers with terms that run through December 31, 2015 or later in the case of Mr. Ungurean. After their specified terms, each of these employment agreements automatically extends for successive one-year periods unless and until either party elects to terminate the agreement by giving at least 90 days written notice prior to the commencement of the next succeeding one-year period. These agreements establish customary employment terms including base salaries, bonuses and other incentive compensation and other benefits. For information regarding the base salaries and other compensation provided under these employment agreements, please refer to the discussion above under “Compensation Discussion and Analysis — Employment and Severance Arrangements.”

These employment agreements also provide for, among other things, the payment of severance benefits and in some cases the continuation of certain benefits following certain terminations of employment by our general partner or the termination of employment for “Good Reason” (as defined in each of the employment agreements) by the executive officer. Under these agreements, if the executive officer’s employment is terminated by our general partner without “Cause” (as defined in the employment agreements) or the executive officer resigns for Good Reason, in each case, during the term of the agreement, the executive officer will have the right to a lump sum cash severance payment by our general partner equal to two times (three times with respect to Mr. Harris for a termination in connection with a change of control occurring after December 31, 2013 and one time with respect to Mr. Gardner) the executive officer’s annual base salary on the date of such termination. In addition, for Mr. Ungurean, in the event of a termination due to death or disability (as such term is defined in the employment agreements), or by our general partner without Cause, he and his dependents will be entitled to continued participation in our general partner’s employee benefit plans and insurance arrangements providing medical and dental benefits in which they are enrolled at the time of such termination for the remainder of the employment term, provided that the continuation is permitted at the time of termination under the terms of our general partner’s employee benefit plans and insurance arrangements. Also, for Mr. Harris, in the event of a termination for which he is entitled to receive such severance payment, he will also be entitled to receive COBRA benefits with the premiums therefor payable by our general partner. Under the employment agreements, if our general partner chooses to terminate the employment of an executive officer without Cause or the executive officer resigns for Good Reason, in each case after the expiration of the agreement following notice by our general partner that it is not renewing the term of the agreement, the executive officer would be entitled to a lump sum payment equal to two times (three times with respect to Mr. Harris for a termination in connection with a change of control occurring after December 31, 2013 and one time with respect to Mr. Gardner) the executive officer’s base salary. Mr. Harris would also be entitled to the COBRA benefits described above with the premiums therefor being payable by our general partner. All of the foregoing severance benefits are conditioned on the executive officer executing a release of claims in favor of our general partner and its affiliates including us. All of the severance benefits paid by our general partner are subject to reimbursement by us.

“Cause” is defined in each employment agreement as the executive officer having (i) engaged in gross negligence, gross incompetence or willful misconduct in the performance of the duties required of him under the employment agreement, (ii) refused (failed in the case of Mr. Harris) without proper reason to perform the duties and responsibilities required of him under the employment agreement (and in the case of Mr. Harris, such failure has continued without cure for a period of 30 days or more after our general partner has given him written notice of such failure), (iii) willfully engaged in conduct that is materially injurious to our general partner or its affiliates including us (monetarily or otherwise), (iv) committed an act of fraud, embezzlement or willful breach of fiduciary duty to our general partner or an affiliate (including the unauthorized disclosure of confidential or proprietary material information of our general partner or an affiliate or, in the case of Messrs. Harris and Maher only, including instead the unauthorized disclosure of information that is, and is known or reasonably should have been known to the executive officer to be, confidential or proprietary information (material information in the case of Mr. Harris) of our general partner or an affiliate) or (v) been convicted of (or pleaded no contest to) a crime involving fraud, dishonesty or moral turpitude or any felony. “Good Reason” is defined in each employment agreement as a termination by the executive officer in connection with or based upon (i) a material diminution in the executive officer’s responsibilities, duties or authority, (ii) a material diminution in the executive officer’s base compensation (or in the case of Messrs. Harris and Maher, the executive officer’s base compensation or the amount of the target annual bonus that may be earned by him) or (iii) a material breach by our general partner of any material provision of the employment agreement, and additionally in the case of Mr. Harris only, (iv) relocation of his principal place of employment from our general partner’s executive office to a location more than 30 miles from the city limits of Columbus, Ohio.

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Each employment agreement also contains certain confidentiality covenants prohibiting each executive officer from, among other things, disclosing confidential information relating to our general partner or any of its affiliates including us. The employment agreements also contain non-competition and non-solicitation restrictions. For Mr. Ungurean, those provisions apply during the term of his agreement and continue for a period of two years following termination of employment for any reason. In the cases of Messrs. Harris, Maher, Honish and Gardner, those provisions apply during the term of their respective employment with our general partner and continue for a period of 12 months following termination of employment for any reason if such termination occurs during the term of the employment agreement and not in connection with the expiration of the employment agreement. In addition, in connection with the contribution of Oxford Mining Company to us in August 2007, Mr. Ungurean agreed that he would not compete with us in the coal mining business in Illinois, Kentucky, Ohio, Pennsylvania, West Virginia and Virginia before August 24, 2014.

The following table shows the value of the severance benefits and other benefits for the named executive officers under their employment agreements as in effect on December 31, 2013, assuming each named executive officer had terminated employment on December 31, 2013.

Name	Payment Type	Death or Disability ($)		Termination Without Cause ($)			Resignation for Good Reason ($)
Charles C. Ungurean	Cash severance			$	1,000,000		$	1,000,000
	Benefit Continuation	$	28,434		28,434
	Total		28,434		1,028,434			1,000,000
Bradley W. Harris	Cash severance				600,000	(1)		600,000	(1)
	Benefit Continuation				22,344			22,344
	Total				622,344			622,344
Daniel M. Maher	Cash severance				540,000			540,000
Gregory J. Honish	Cash severance				420,000			420,000
Michael B. Gardner	Cash severance				170,000			170,000

(1) For Mr. Harris, if the termination were in connection with a change in control, the cash severance benefit would be $900,000.

Except as described in the following sentence, our named executive officers are not entitled to any additional payments or benefits upon the occurrence of a change in control with respect to us or our general partner. The employment agreements of all of our named executive officers provide that, upon the occurrence of a change in control with respect to us or our general partner, all of the awards granted to them under our LTIP that have not vested as of the date of the change in control will immediately vest. Assuming that a change of control with respect to us or our general partner had occurred on December 31, 2013, each of our named executive officers would have been entitled to accelerated vesting with respect to all unvested phantom units that he held as of such date (160,077 units for Mr. Ungurean having an aggregate market value as of such date of $196,895, 117,878 units for Mr. Harris having an aggregate market value as of such date of $144,990, 88,807 units for Mr. Maher having an aggregate market value as of such date of $109,233, 67,540 units for Mr. Honish having an aggregate market value as of such date of $83,074, and 23,915 units for Mr. Gardner having an aggregate market value as of such date of $29,415, in each case with the value being based on the closing price of our common units of $1.23 on such date). In connection with his employment by us, Mr. Maher received Class B units in our general partner representing a profits participation interest in our general partner, which units vest over the four-year period following his receipt of such Class B units and are subject to accelerated vesting upon a change in control with respect to us or our general partner. Assuming that a change in control with respect to us or our general partner had occurred on December 31, 2013, Mr. Maher would have been entitled to accelerated vesting with respect to the 3.1720195 such Class B units that were unvested on such date at an estimated aggregate fair market value as of such date of $1,234 determined in accordance with FASB ASC Topic 718.

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Compensation of Directors

Our general partner’s non-employee directors are compensated for their service as directors under our general partner’s Non-Employee Director Compensation Plan. Our non-employee directors for purposes of the plan are directors that (i) are not an officer or employee of our general partner or any of its subsidiaries or affiliates, (ii) are not affiliated with or related to any party that receives compensation from our general partner or any of its subsidiaries and affiliates, and (iii) have not entered into an arrangement with our general partner or any of its subsidiaries and affiliates to receive compensation from any such entity other than in respect of his services as a member of the board of directors. In addition, other members of the board of directors that are not employees of our general partner can be approved by the board of directors for participation in such plan, effective as of January 1 of the calendar year following such approval.

Each non-employee director covered by the plan receives an annual compensation package consisting of the following:

● a cash retainer of $50,000;

● an annual unit grant having a value of $50,000; and

● where applicable, a committee chair retainer for each committee chaired of $10,000.

In addition, each non-employee director receives the following per meeting fees:

● per meeting fees for board meetings attended in person of $2,000; and

● per meeting fees for telephonic board meetings and committee meetings of $500.

In addition, in connection with the initial election of a non-employee director, the board of directors of our general partner may determine that such non-employee directors will receive a one-time grant of unrestricted common units. Furthermore, each non-employee director may elect to receive the cash components of his compensation under the plan, as outlined above, in the form of unrestricted common units granted under our LTIP representing an equivalent value at the date of issuance. Such elections must be made in advance of the year in which the compensation is earned or at the directors’ initial appointment. The annual compensation package is paid to each non-employee director based on his or her service for the period beginning upon the date of his or her appointment to the board. If a non-employee director’s service commences after the first day of a calendar year, such non-employee director will receive a prorated annual compensation package for such year. The annual board membership retainer and, if applicable, committee chair retainer are paid in quarterly installments. The annual unit grants are also paid in quarterly installments of units having equivalent fair market value on the date of issuance to one fourth of the total annual grant value described above. If board membership or committee chairmanship terminates during the year, amounts due on subsequent quarterly payment dates would not be paid. Units awarded to non-employee directors under the annual compensation package or upon first election to the board, and any units issued upon a non-employee director’s election to receive units in lieu of cash compensation, are granted under our LTIP and vest on the date of grant. Cash distributions will be paid on these units from and after the time of their issuance. Each non-employee director is also reimbursed for out-of-pocket expenses in connection with attending meetings of the board or its committees. Each director will be indemnified by us for actions associated with being a director of our general partner to the fullest extent permitted under Delaware law.

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Director Compensation Table for 2013

The following table sets forth the compensation paid to our non-employee directors for the year ended December 31, 2013, as described above.  None of our non-employee directors held any unvested units as of December 31, 2013.

Name	Fees ($)(1)		Unit Awards ($)(2)		Total ($)
Gerald A. Tywoniuk	$	94,000	$	50,004	$	144,004
Peter B. Lilly	$	90,000	$	50,004	$	140,004
Robert J. Messey	$	76,000	$	50,004	$	126,004

(1) The amounts in this column represent the fees paid to the directors in 2013.  All of the fees were paid in cash.

(2) The amounts in this column represent the value of unit awards made to directors under our LTIP in 2013. For each of the directors, (a) 4,546 units were granted and vested on March 31, 2013 and their market value is based on the closing price of $2.75 per unit on March 29, 2014 (as the NYSE was closed on the March 30 and March 31, 2013 weekend dates); (b) 4,682 units were granted and vested on June 30, 2013 and their market value is based on the closing price of $2.67 per unit on June 28, 2013 (as the NYSE was closed on the June 29 and June 30, 2013 weekend dates); (c) 6,411 units were granted and vested on September 30, 2013 and their market value is based on the closing price of $1.95 per unit on such date; and (d) 10,163 units were granted and vested on December 31, 2013 and their market value is based on the closing price of $1.23 per unit on such date.

Compensation Committee Interlocks and Insider Participation

Brian D. Barlow, Peter B. Lilly, Gerald A. Tywoniuk and Robert J. Messey serve as the members of the Compensation Committee. Mr. Barlow serves as the chairman of the Compensation Committee. For a description of certain transactions between us and affiliates of Mr. Barlow, see “Item 13. Certain Relationships and Related Transactions, and Director Independence.”

Item 12.                 Security Ownership of Certain Beneficial Owners and Management and Related Unitholder Matters

The following table sets forth certain information regarding the beneficial ownership of units as of February 28, 2014 (the “Ownership Reference Date”) by:

● each person who is known to us to beneficially own 5% or more of such units to be outstanding;

● our general partner;

● each of the directors and named executive officers of our general partner; and

● all of the directors and executive officers of our general partner as a group.

All information with respect to beneficial ownership has been furnished by the respective directors, officers or 5% or more unitholders as the case may be.

The equity interests of our general partner are comprised of Class A units and Class B units.  The Class B units represent only profits interests in our general partner from the date of issuance.  The Class A units of our general partner are owned 33.7% by C&T Coal and 66.3% by AIM Oxford (both of which are reflected as 5% or more unitholders in the table below).  C&T Coal is owned by Charles C. Ungurean, our President and Chief Executive Officer, and Thomas T. Ungurean, our former Senior Vice President, Equipment, Procurement and Maintenance, and AIM Oxford is owned by AIM Coal LLC and certain investment partnerships affiliated with American Infrastructure MLP Fund, L.P.  The Class B units of our general partner are owned 67.3% by Daniel M. Maher, our Senior Vice President, Chief Legal Officer and Secretary, and 32.7% by Jeffrey M. Gutman, our former Senior Vice President, Chief Financial Officer and Treasurer.

The amounts and percentage of units beneficially owned are reported on the basis of regulations of the SEC governing the determination of beneficial ownership of securities.  Under the rules of the SEC, a person is deemed to be a “beneficial owner” of a security if that person has or shares “voting power,” which includes the power to vote or to direct the voting of such security, or “investment power,” which includes the power to dispose of or to direct the disposition of such security.  In computing the number of common units beneficially owned by a person and the percentage ownership of that person, common units subject to options or warrants held by that person that are currently exercisable or exercisable within 60 days of the Ownership Reference Date, if any, are deemed outstanding, but are not deemed outstanding for computing the percentage ownership of any other person.  Except as indicated by footnote, the persons named in the table below have sole voting and investment power with respect to all units shown as beneficially owned by them, subject to community property laws where applicable.

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The percentage of units beneficially owned is based on a total of 10,589,149 common units and 10,280,380 subordinated units outstanding as of the Ownership Reference Date.

Name of Beneficial Owner	Common Units to be Beneficially Owned		Percentage of Common Units to be Beneficially Owned			Subordinated Units to be Beneficially Owned		Percentage of Subordinated Units to be Beneficially Owned			Percentage of Total Common and Subordinated Units to be Beneficially Owned
AIM Oxford Holdings, LLC(1)(2)		709,143		6.7	%		6,813,160		66.3	%		36.0	%
C&T Coal, Inc.(3)		360,882		3.4	%		3,467,220		33.7	%		18.3	%
Pacific Investment Management Company LLC.(4)		1,256,617		11.9	%		—		—			6.0	%
Advisory Research, Inc.(5)		1,198,175		11.3	%		—		—			5.7	%
George E. McCown(1)(2)(6)		709,143		6.7	%		6,813,160		66.3	%		36.0	%
Brian D. Barlow(2)		—		—			—		—			—
Matthew P. Carbone(1)(2)(6)		709,143		6.7	%		6,813,160		66.3	%		36.0	%
Gerald A. Tywoniuk(3)(7) (9)		47,937		*			—		—			*
Peter B. Lilly(3)(9)		71,410		*			—		—			*
Robert J. Messey(3)(8)(9)		54,795		*			—		—			*
Charles C. Ungurean(3)(10)(11)		385,188		3.6	%		3,467,220		33.7	%		18.5	%
Thomas T. Ungurean(3)(10)(12)		366,313		3.5	%		3,467,220		33.7	%		18.4	%
Bradley W. Harris(3)(13)		66,086		*			—		—			*
Gregory J. Honish(3)(14)		21,957		*			—		—			*
Daniel M. Maher(3)(15)		21,064		*			—		—			*
Michael B. Gardner(3)(16)		17,330		*			—		—			*
All directors and executive officers as a group (consisting of 12 persons)		1,416,264		13.4	%		10,280,380		100.0	%		56.0	%

An asterisk indicates that the person or entity owns less than one percent.

(1) AIM Oxford Holdings, LLC is governed by its sole manager, AIM Coal Management, LLC, a Delaware limited liability company. AIM Coal Management, LLC’s members consist of George E. McCown and Matthew P. Carbone, both directors of our general partner, and Robert B. Hellman, Jr. Messrs. McCown, Carbone and Hellman, in their capacities as members of AIM Coal Management, LLC, share voting and investment power with respect to the common and subordinated units owned by AIM Oxford Holdings, LLC.

(2) The address for this person or entity is 950 Tower Lane, Suite 800, Foster City, California 94404.

(3) The address for this person or entity is 41 South High Street, Suite 3450, Columbus, Ohio 43215.

(4) The address for this person or entity is c/o Boston Financial Data Services, Inc., 330 West 9th Street, Kansas City, Missouri 54105.

(5) The address for this person or entity is Two Prudential Plaza, 180 N. Stetson Avenue, Suite 5500, Chicago, Illinois 60601.

(6) Each of Messrs. McCown and Carbone disclaim beneficial ownership of the units, except to the extent of any pecuniary interest therein.

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(7) A total of 37,937 of these common units are owned by a trust established and trusteed by Mr. Tywoniuk. Mr. Tywoniuk disclaims beneficial ownership of the units held by such trust, except to the extent of any pecuniary interest therein.

(8) A total of 6,000 of these common units are owned by a trust established by Mr. Messey and his spouse. Mr. Messey disclaims beneficial ownership of the units held by such trust, except to the extent of any pecuniary interest therein.

(9) The common units shown for Messrs. Tywoniuk, Lilly and Messey include common units which will vest and be issued to them on March 31, 2014. The number of such units which will vest and be issued are estimated because the actual number to be issued to each of them will be dependent upon the closing price for the units on March 31, 2014. Each of them will have units having a value of $12,500 at such closing price (estimated at 10,000 units based on an estimated closing price of $1.25 per unit) issued to him.

(10) Charles C. Ungurean and Thomas T. Ungurean, as the shareholders of C&T Coal, Inc., share voting and investment power with respect to the common and subordinated units owned by C&T Coal, Inc. Each of Charles C. Ungurean and Thomas T. Ungurean disclaim beneficial ownership of the units, except to the extent of any pecuniary interest therein.

(11) Does not include 546,891 common units that could be issuable upon the vesting of phantom units, which phantom units will not vest within 60 days of the Ownership Reference Date.

(12) Does not include 22,772 common units that could be issuable upon the vesting of phantom units, which phantom units will not vest within 60 days of the Ownership Reference Date.

(13) Does not include 328,297 common units that could be issuable upon the vesting of phantom units, which phantom units will not vest within 60 days of the Ownership Reference Date.

(14) Does not include 229,758 common units that could be issuable upon the vesting of phantom units, which phantom units will not vest within 60 days of the Ownership Reference Date.

(15) Does not include 294,332 common units that could be issuable upon the vesting of phantom units, which phantom units will not vest within 60 days of the Ownership Reference Date.

(16) Does not include 86,560 common units that could be issuable upon the vesting of phantom units, which phantom units will not vest within 60 days of the Ownership Reference Date.

Securities Authorized for Issuance under Equity Compensation Plans

The following table provides information concerning common units that may be issued under our LTIP. Our LTIP allows for awards of options, phantom units, restricted units, unit awards, other unit awards and unit appreciation rights. It currently permits the grant of awards covering an aggregate of 2,806,075 units. Our LTIP is administered by the Compensation Committee.

The board of directors of our general partner in its discretion may terminate, suspend or discontinue our LTIP at any time with respect to any award that has not yet been granted. The board of directors of our general partner also has the right to alter or amend our LTIP or any part of our LTIP from time to time, including increasing the number of units that may be granted subject to unitholder approval as required by the exchange upon which the common units are listed at that time. However, no change in any outstanding grant may be made that would materially impair the rights of the participant without the consent of the participant.

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The following table summarizes the number of securities remaining available for future issuance under our LTIP as of December 31, 2013.

Plan Category	Number of Securities to be Issued Upon Exercise of Outstanding Options, Warrants and Rights		Weighted-Average Exercise Price of Outstanding Options, Warrants and Rights		Number of Securities Remaining Available for Future Issuance Under Equity Compensation Plans (Excluding Securities Reflected in Column(a))
	(a)		(b)		(c)
Equity compensation plans approved by security holders(1)		—	$	—		1,623,185	(2)
Equity compensation plans not approved by security holders		—		—		—
Total		—	$	—		1,623,185	(2)

(1) Our LTIP was approved by our partners (general and limited) prior to our initial public offering. Our LTIP currently permits the grant of awards covering an aggregate of 2,806,705 units, inclusive of prior award grants, which grants did not and do not require approval by our limited partners.

(2) The number of remaining available units for award grants includes the units that would be issuable upon vesting of a total of 559,184 outstanding phantom units.

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Item 13.                 Certain Relationships and Related Transactions, and Director Independence

At December 31, 2013, C&T Coal owned 360,882 common units and 3,467,220 subordinated units representing a combined 18.0% limited partner interest in us, and AIM Oxford owned 709,143 common units and 6,813,160 subordinated units representing a combined 35.3% limited partner interest in us. C&T Coal and AIM Oxford control our general partner which owns a 2.0% general partner interest in us and all of our incentive distribution rights. The equity interests of our general partner are comprised of class A units and class B units. The class B units represent only profits interests in our general partner from the date of issuance. The class A units of our general partner are owned 33.7% by C&T Coal and 66.3% by AIM Oxford. C&T Coal is owned by Charles C. Ungurean, a member of our management team, and Thomas T. Ungurean, a member of our management team until his resignation effective June 30, 2012, and AIM Oxford is owned by AIM Coal LLC and certain investment partnerships affiliated with AIM. The class B units of our general partner are owned 32.7% by Jeffrey M. Gutman, a member of our management team until his resignation effective October 1, 2012, and 67.3% by Daniel M. Maher, a member of our management team.

Distributions and Payments to Our General Partner and Its Affiliates

The following table summarizes the distributions and payments to be made by us to our general partner and its affiliates in connection with our ongoing operations and liquidation. These distributions and payments were determined by and among affiliated entities, and, consequently, are not the result of arm’s-length negotiations.

Ongoing Operations Stage
Distributions of available cash to our general partner and its affiliates	We will make cash distributions 98.0% to the unitholders, including affiliates of our general partner as the holders of an aggregate of 1,070,025 common units and all of the subordinated units, and 2.0% to our general partner. If distributions exceed the minimum quarterly distribution and the first target distribution level, our general partner will be entitled to increasing percentages of the distributions, up to 48.0% of the distributions above the highest target distribution level. Assuming we have sufficient available cash to pay the full minimum quarterly distribution on all of our outstanding units for four quarters, our general partner and its affiliates would receive an annual distribution of approximately $0.7 million on the 2.0% general partner interest and approximately $19.9 million on their common units and subordinated units.
Payments to our general partner and its affiliates	Our general partner will not receive a management fee or other compensation for its management of us. Our general partner and its affiliates will be reimbursed for expenses incurred on our behalf. Our partnership agreement provides that our general partner will determine the amount of these expenses.
Withdrawal or removal of our general partner	If our general partner withdraws or is removed, its general partner interest and its incentive distribution rights will either be sold to the new general partner for cash or converted into common units, in each case for an amount equal to the fair market value of those interests.

Liquidation Stage
Liquidation	Upon our liquidation, the partners, including our general partner, will be entitled to receive liquidating distributions according to their particular capital account balances.

Ownership Interests of Certain Executive Officers and Directors of Our General Partner

C&T Coal, AIM Oxford, Jeffrey M. Gutman, and Daniel M. Maher collectively own 100.0% of our general partner. Charles C. Ungurean, the President and Chief Executive Officer of our general partner, and Thomas T. Ungurean, a former officer of our general partner, own all of the equity interests in C&T Coal. 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 having ownership interests in AIM. Jeffrey M. Gutman is a former officer of our general partner, and Daniel M. Maher is the Senior Vice President, Chief Legal Officer and Secretary of our general partner.

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In addition to the 2.0% general partner interest in us, our general partner owns the incentive distribution rights, which entitle the holder to increasing percentages, up to a maximum of 48.0%, of the cash we distribute in excess of $0.6563 per quarter.

Administrative and Operational Services Agreement

On August 24, 2007, we entered into an administrative and operational services agreement with Oxford Mining Company, LLC and our general partner. Under the agreement, our general partner provides services to us and is reimbursed for all related costs incurred on our behalf. The services that our general partner provides include, among other things, general administrative and management services, human resources, information technology, finance and accounting, corporate development, real property, marketing, engineering, operations (including mining operations), geologic services, risk management and insurance services. During 2013, we paid our general partner approximately $66.7 million for services, primarily related to payroll, performed under the administrative and operational services agreement. Any party may terminate the administrative and operational services agreement by providing at least 30 days’ written notice to the other parties.

Investors’ Rights Agreement

We entered into an investors’ rights agreement on August 24, 2007 with our general partner, C&T Coal, AIM Oxford, Charles C. Ungurean and Thomas C. Ungurean. Pursuant to such agreement and subject to certain restrictions, C&T Coal was granted certain demand and “piggyback” registration rights. Pursuant to the agreement, C&T Coal has the right to require us to file a registration statement for the public sale of all of the common and subordinated units it owns at any time after our initial public offering. In addition and subject to certain restrictions, if we sell any common units in a registered underwritten offering, C&T Coal will have the right to include its common units in that offering. However, the managing underwriter or underwriters of any such offering will have the right to limit the number of common units to be included in such sale. We will pay all expenses relating to any demand or piggyback registration, except for fees and disbursements of any counsel retained by C&T Coal and any underwriter or brokers’ commission or discounts.

In addition, the investors’ rights agreement gives C&T Coal the right to designate a number of directors to the board of directors of our general partner proportionate to its percentage share of the total outstanding membership interests in our general partner. AIM Oxford has the right to designate the remaining members of the board of directors of our general partner. However, the number of directors C&T Coal has the right to appoint will be reduced if necessary such that the number of directors appointed by C&T Coal and the number of independent directors (as defined in our partnership agreement) are less than fifty percent of the members of the board, provided that the number of directors C&T Coal has the right to appoint is not less than one. C&T Coal’s right to designate members of the board of directors of our general partner will terminate upon C&T Coal, Charles C. Ungurean and Thomas T. Ungurean ceasing to own in the aggregate at least 5% of our common units and subordinated units.

Furthermore, the investors’ rights agreement gives C&T Coal, Charles C. Ungurean and Thomas T. Ungurean tag-along rights to sell their limited partner interests in us in any case where AIM Oxford requires C&T Coal, Charles C. Ungurean and Thomas T. Ungurean, pursuant to the investors’ rights agreement, to sell their interest in our general partner in connection with the sale by AIM Oxford of all of its interests in us and our general partner to a non-affiliated third party. All of the other rights provided for in the investors’ rights agreement related to dispositions of interests in us by AIM Oxford or C&T Coal, Charles C. Ungurean and Thomas T. Ungurean terminated upon the closing of our initial public offering.

Tunnell Hill Reclamation LLC

We were a party to an environmental services agreement with Tunnell Hill Reclamation LLC (“Tunnell Hill”), a wholly owned subsidiary of Tunnel Hill Partners, LP (“Tunnel Hill Partners”), pursuant to which we provided certain landfill operational services. The services agreement was terminated effective August 1, 2011 (the “Termination Date”). In connection with the termination of the services agreement, we entered into a Transaction Agreement and related documents with Tunnell Hill, effective as of the Termination Date, under which Tunnell Hill temporarily leased from us for a period of six months certain of our equipment and had an option during the six month leasing period to elect to purchase all of the equipment for a purchase price of $948,000 with 50% of the rental payments being credited against the purchase price should Tunnell Hill elect to exercise its purchase option. In the first quarter of 2012, Tunnell Hill exercised its option to purchase the leased equipment and we received net proceeds of approximately $877,000, which reflects the purchase price of $948,000 less a credit of 50% of the rental payments received during the lease period and recognized a gain on this transaction of approximately $97,000. Payments received for contract services provided to Tunnell Hill totaled $24,000 and $1,525,000 for the years ended December 31, 2012 and 2011, respectively. We continue to sell clay and small quantities of coal to Tunnell Hill which totaled $385,000 and 181,000 for the years ended December 31, 2013 and 2012, respectively.

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In addition, pursuant to a mining agreement, Tunnell Hill granted us access to certain properties for the purpose of conducting mining operations. As consideration for such access, we authorized the construction by Tunnell Hill of future landfills or other waste disposal facilities on such properties.

The vast majority of the ownership interest in Tunnel Hill Partners is directly or indirectly owned by T&C Holdco, LLC and AIM Tunnel Hill Holdings II, LLC. T&C Holdco is wholly-owned by Charles C. Ungurean and Thomas T. Ungurean. AIM Tunnel Hill Holdings II, LLC is indirectly owned by AIM.

Chartering of Aircraft Transportation

From time to time for business purposes, we charter the use of various airplanes from Zanesville Aviation located in Zanesville, Ohio. Additionally, C&T Coal owns an airplane that it leases to Zanesville Aviation and Zanesville Aviation uses that airplane in providing charter services to its customers, including us at times. During the years of 2013, 2012 and 2011, we paid Zanesville Aviation an aggregate of $97,000, $146,000, and $178,000, respectively.

Procedures for Review, Approval and Ratification of Related Person Transactions

The board of directors of our general partner has adopted a code of business conduct and ethics that provides that the board of directors of our general partner or its authorized committee will periodically review all related person transactions that are required to be disclosed under SEC rules and, when appropriate, initially authorize or ratify all such transactions. In the event that the board of directors of our general partner or its authorized committee considers ratification of a related person transaction and determines not to so ratify, the code of business conduct and ethics provides that our management will make all reasonable efforts to cancel or annul the transaction.

The code of business conduct and ethics provides that, in determining whether or not to recommend the initial approval or ratification of a related person transaction, the board of directors of our general partner or its authorized committee should consider all of the relevant facts and circumstances available, including (if applicable) but not limited to: (i) whether there is an appropriate business justification for the transaction; (ii) the benefits that accrue to us as a result of the transaction; (iii) the terms available to unrelated third parties entering into similar transactions; (iv) the impact of the transaction on a director’s independence (in the event the related person is a director, an immediate family member of a director or an entity in which a director or an immediately family member of a director is a partner, shareholder, member or executive officer); (v) the availability of other sources for comparable products or services; (vi) whether it is a single transaction or a series of ongoing, related transactions; and (vii) whether entering into the transaction would be consistent with the code of business conduct and ethics.

The code of business conduct and ethics described above was adopted in connection with the closing of our initial public offering, and as a result the transactions described above were not reviewed under such policy. A copy of the code of business conduct and ethics is found at www.oxfordresources.com in the Investor Relations/Corporate Governance section. Additionally a unitholder may make such a request in writing by mailing such request to Investor Relations, Oxford Resource Partners, LP, 41 South High Street, Suite 3450, Columbus, Ohio 43215, or by emailing such request to Investor Relations at ir@OxfordResources.com.

Further information required for this item is provided in “Item 1. Business — Overview,” “Item 10. Directors, Executive Officers and Corporate Governance” and Note 19: Related Party Transactions included in the notes to the consolidated financial statements included in “Item 8 — Financial Statements and Supplementary Data.”

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Item 14.                 Principal Accountant Fees and Services

The following table sets forth fees and out-of-pocket expenses billed by Grant Thornton LLP for the audit of our annual financial statements and other services rendered for the fiscal years ended December 31, 2013 and 2012:

	For the Year Ended December 31,
Name	2013		2012
Audit fees(1)	$	296,000	$	383,000

(1) Includes fees and expenses for audits of annual financial statements of our subsidiaries, reviews of the related quarterly financial statements, services related to testing our internal controls over financial reporting and services that are normally provided by the independent accountants in connection with statutory and regulatory filings or engagements, including reviews of documents filed with the SEC.

Pursuant to the charter of the Audit Committee, the Audit Committee is responsible for the oversight of our accounting, reporting and financial practices. The Audit Committee is responsible for the appointment, compensation, retention and oversight of the work of our external auditors; the pre-approval of all audit and non-audit services to be provided, consistent with all applicable laws, to us by our external auditors; and the establishment of the fees and other compensation to be paid to our external auditors. The Audit Committee also oversees and directs our internal auditing program and reviews our internal controls.

The Audit Committee has adopted a policy for the pre-approval of audit and permitted non-audit services provided by our principal independent accountants. The policy requires that all services provided by Grant Thornton LLP, including audit services, audit-related services, tax services and other services, must be pre-approved by the Audit Committee.

The Audit Committee reviews the external auditors’ proposed scope and approach as well as the performance of the external auditors. It also has direct responsibility for resolution of and sole authority to resolve any disagreements between our management and our external auditors regarding financial reporting, regularly reviews with the external auditors any problems or difficulties the auditors encounter in the course of their audit work, and, at least annually, uses its reasonable efforts to obtain and review a report from the external auditors addressing the following (among other items):

• the external auditors’ internal quality-control procedures;

• any material issues raised by the most recent internal quality-control review, or peer review, of the external auditors;

• the independence of the external auditors;

• the aggregate fees billed by the external auditors for each of the previous two fiscal years; and

• the rotation of the external auditors’ lead partner.

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PART IV

Item 15.             Exhibits and Financial Statement Schedules

(a)1. Financial Statements. See “Index to Financial Statements” on page F-1.

(a)2. Financial Statement Schedules. Other schedules are omitted because they are not required or applicable, or the required information is included in our consolidated financial statements or related notes.

(a)3. Exhibits. See “Index to Exhibits.”

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INDEX TO CONSOLIDATED FINANCIAL STATEMENTS 

Oxford Resource Partners, LP and Subsidiaries

Report of Independent Registered Public Accounting Firm	F-2
Consolidated Balance Sheets as of December 31, 2013 and 2012	F-3
Consolidated Statements of Operations for the years ended December 31, 2013, 2012 and 2011	F-4
Consolidated Statements of Partners’ (Deficit) Capital for the years ended December 31, 2013, 2012 and 2011	F-5
Consolidated Statements of Cash Flows for the years ended December 31, 2013, 2012 and 2011	F-6
Notes to Consolidated Financial Statements	F-7

F-1 

REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

Board of Directors and Unitholders of

Oxford Resource Partners, LP

We have audited the accompanying consolidated balance sheets of Oxford Resource Partners, LP (a Delaware limited partnership) and subsidiaries (the “Partnership”) as of December 31, 2013 and 2012, and the related consolidated statements of operations, partners’ (deficit) capital and cash flows for each of the three years in the period ended December 31, 2013. These financial statements are the responsibility of the Partnership’s management. Our responsibility is to express an opinion on these financial statements based on our audits.

We conducted our audits in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. We were not engaged to perform an audit of the Partnership’s internal control over financial reporting. Our audits included consideration of internal control over financial reporting as a basis for designing audit procedures that are appropriate in the circumstances, but not for the purpose of expressing an opinion on the effectiveness of the Partnership’s internal control over financial reporting. Accordingly, we express no such opinion. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements, assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.

In our opinion, the consolidated financial statements referred to above present fairly, in all material respects, the financial position of Oxford Resource Partners, LP and subsidiaries as of December 31, 2013 and 2012, and the results of their operations and their cash flows for each of the three years in the period ended December 31, 2013, in conformity with accounting principles generally accepted in the United States of America.

/s/ GRANT THORNTON LLP

Cleveland, Ohio

March 4, 2014

F-2 

OXFORD RESOURCE PARTNERS, LP AND SUBSIDIARIES

CONSOLIDATED BALANCE SHEETS

(in thousands, except for unit data)

	As of December 31,
	2013			2012
ASSETS
CURRENT ASSETS:
Cash	$	3,089		$	3,977
Accounts receivable		25,850			19,792
Inventory		13,840			12,554
Advance royalties		2,604			4,461
Prepaid expenses and other assets		1,737			2,046
Assets held for sale		-			6,106
Total current assets		47,120			48,936
PROPERTY, PLANT AND EQUIPMENT, NET		144,426			158,483
ADVANCE ROYALTIES, LESS CURRENT PORTION		8,800			4,861
INTANGIBLE ASSETS, NET		1,188			1,442
OTHER LONG-TERM ASSETS		22,821			7,177
Total assets	$	224,355		$	220,899
LIABILITIES AND PARTNERS' (DEFICIT) CAPITAL
CURRENT LIABILITIES:
Accounts payable	$	23,932		$	26,893
Current portion of long-term debt		7,901			102,970
Current portion of reclamation and mine closure costs		5,996			3,869
Accrued taxes other than income taxes		1,293			1,213
Accrued payroll and related expenses		3,389			1,629
Other liabilities		3,457			2,491
Total current liabilities		45,968			139,065
LONG-TERM DEBT		155,375			41,557
RECLAMATION AND MINE CLOSURE COSTS		25,658			25,144
WARRANTS		4,599			-
OTHER LONG-TERM LIABILITIES		3,753			3,806
Total liabilities		235,353			209,572
PARTNERS’ (DEFICIT) CAPITAL:
Limited partners (20,867,073 and 20,751,190 units outstanding as of December 31, 2013 and 2012, respectively)		(13,460	)		9,593
General partner (423,494 units outstanding as of December 31, 2013 and 2012)		(2,507	)		(2,010	)
Total Oxford Resource Partners, LP (deficit) capital		(15,967	)		7,583
Noncontrolling interest		4,969			3,744
Total partners’ (deficit) capital		(10,998	)		11,327
Total liabilities and partners’ (deficit) capital	$	224,355		$	220,899

See accompanying notes to consolidated financial statements.

F-3 

OXFORD RESOURCE PARTNERS, LP AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF OPERATIONS

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

	For the Year Ended December 31,
	2013			2012			2011
REVENUES:
Coal sales	$	336,201		$	364,928		$	391,046
Other revenue		10,566			8,599			9,331
Total revenues		346,767			373,527			400,377
COSTS AND EXPENSES:
Cost of coal sales:
Produced coal		268,130			288,782			316,574
Purchased coal		22,297			23,685			13,480
Total cost of coal sales (excluding depreciation, depletion and amortization)		290,427			312,467			330,054
Cost of other revenue		1,619			1,195			1,799
Depreciation, depletion and amortization		48,081			51,170			51,905
Selling, general and administrative expenses		17,297			15,629			13,739
Impairment and restructuring expenses		1,761			15,650			-
(Gain) loss on disposal of assets, net		(6,488	)		(8,021	)		1,352
Total costs and expenses		352,697			388,090			398,849
(LOSS) INCOME FROM OPERATIONS		(5,930	)		(14,563	)		1,528
INTEREST AND OTHER EXPENSES:
Interest income		4			10			13
Interest expense		(21,054	)		(11,500	)		(9,870	)
Change in fair value of warrants		3,280			-			-
Total interest and other expenses		(17,770	)		(11,490	)		(9,857	)
NET LOSS		(23,700	)		(26,053	)		(8,329	)
Net income attributable to noncontrolling interest		(1,225	)		(755	)		(4,748	)
Net loss attributable to Oxford Resource Partners, LP unitholders		(24,925	)		(26,808	)		(13,077	)
Net loss allocated to general partner		(497	)		(535	)		(261	)
Net loss allocated to limited partners	$	(24,428	)	$	(26,273	)	$	(12,816	)
Net loss per limited partner unit:
Basic	$	(1.07	)	$	(1.27	)	$	(0.62	)
Diluted	$	(1.07	)	$	(1.27	)	$	(0.62	)
Weighted average number of limited partner units outstanding:
Basic		22,776,481			20,711,952			20,641,127
Diluted		22,776,481			20,711,952			20,641,127
Distributions paid per unit:
Limited partners:
Common	$	-		$	1.5125		$	1.7500
Subordinated	$	-		$	0.6375		$	1.7500
General partner	$	-		$	1.0750		$	1.7500

See accompanying notes to consolidated financial statements. 

 F-4

OXFORD RESOURCE PARTNERS, LP AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF PARTNERS’ (DEFICIT) CAPITAL

(in thousands, except for unit data)

	Limited Partners																							Total
	Common					Subordinated					Total					General Partner					Non-			Partners'
	Units		Capital			Units		Deficit			Units		Capital (Deficit)			Units		Deficit			controlling Interest			Capital (Deficit)
Balance at December 31, 2010		10,330,603	$	146,078			10,280,380	$	(40,394	)		20,610,983	$	105,684			420,633	$	(63	)	$	3,142		$	108,763
Net (loss) income		-		(6,437	)		-		(6,379	)		-		(12,816	)		-		(261	)		4,748			(8,329	)
Partner contributions		-		-			-		-			-		-			1,411		28			-			28
Partner distributions		-		(18,129	)		-		(17,978	)		-		(36,107	)		-		(736	)		(4,901	)		(41,744	)
Equity-based compensation		-		1,077			-		-			-		1,077			-		-			-			1,077
Issuance of units to LTIP participants		69,141		(678	)		-		-			69,141		(678	)		-		-			-			(678	)
Balance at December 31, 2011		10,399,744		121,911			10,280,380		(64,751	)		20,680,124		57,160			422,044		(1,032	)		2,989			59,117
Net (loss) income		-		(13,237	)		-		(13,036	)		-		(26,273	)		-		(535	)		755			(26,053	)
Partner contributions		-		-			-		-			-		-			1,450		12			-			12
Partner distributions		-		(15,772	)		-		(6,550	)		-		(22,322	)		-		(455	)		-			(22,777	)
Equity-based compensation		-		1,262			-		-			-		1,262			-		-			-			1,262
Issuance of units to LTIP participants		71,066		(234	)		-		-			71,066		(234	)		-		-			-			(234	)
Balance at December 31, 2012		10,470,810		93,930			10,280,380		(84,337	)		20,751,190		9,593			423,494		(2,010	)		3,744			11,327
Net (loss) income		-		(12,374	)		-		(12,054	)		-		(24,428	)		-		(497	)		1,225			(23,700	)
Equity-based compensation		-		1,441			-		-			-		1,441			-		-			-			1,441
Issuance of units to LTIP participants		115,883		(66	)		-		-			115,883		(66	)		-		-			-			(66	)
Balance at December 31, 2013		10,586,693	$	82,931			10,280,380	$	(96,391	)		20,867,073	$	(13,460	)		423,494	$	(2,507	)	$	4,969		$	(10,998	)

See accompanying notes to consolidated financial statements. 

F-5 

OXFORD RESOURCE PARTNERS, LP AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF CASH FLOWS

(in thousands)

	For the Year Ended December 31,
	2013			2012			2011
CASH FLOWS FROM OPERATING ACTIVITIES:
Net loss	$	(23,700	)	$	(26,053	)	$	(8,329	)
Adjustments to reconcile net loss to net cash from operating activities:
Depreciation, depletion and amortization		48,081			51,170			51,905
Impairment and restructuring expenses		1,761			15,650			-
Change in fair value of warrants		(3,280	)		-			-
Interest rate swap and fuel contract adjustments to market		(12	)		(144	)		48
Non-cash interest expense		4,094			-			-
Amortization and write-off of deferred financing costs		3,986			2,175			1,600
Non-cash equity-based compensation expense		1,441			1,262			1,077
Non-cash changes in mine reclamation obligations		2,293			1,567			1,503
Amortization of below-market coal sales contracts		(60	)		(623	)		(939	)
(Gain) loss on disposal of assets, net		(6,488	)		(8,021	)		1,352
Changes in assets and liabilities:
Accounts receivable		(6,058	)		8,596			(280	)
Inventory		(778	)		(554	)		1,731
Advance royalties		(2,320	)		(123	)		(740	)
Restricted cash		(40	)		1,811			(2,179	)
Other assets		147			(1,224	)		(452	)
Accounts payable		(2,962	)		1			866
Reclamation and mine closure costs		(8,222	)		(8,966	)		(5,491	)
Accrued taxes other than income taxes		80			(519	)		89
Accrued payroll and related expenses		1,760			(905	)		(90	)
Other liabilities		(47	)		(1,513	)		(383	)
Net cash from operating activities		9,676			33,587			41,288
CASH FLOWS FROM INVESTING ACTIVITIES:
Purchase of property and equipment		(17,773	)		(19,122	)		(33,859	)
Purchase of coal reserves and land		(1,532	)		(125	)		(1,088	)
Mine development costs		(3,027	)		(3,440	)		(5,196	)
Proceeds from sale of assets		6,424			12,417			849
Insurance proceeds		3,035			400			1,096
Net cash from investing activities		(12,873	)		(9,870	)		(38,198	)
CASH FLOWS FROM FINANCING ACTIVITIES:
Proceeds from borrowings		150,000			-			-
Payments on borrowings		(56,072	)		(10,921	)		(6,231	)
Advances on line of credit		53,588			51,000			62,000
Payments on line of credit		(126,088	)		(39,000	)		(15,000	)
Debt issuance costs		(9,569	)		(1,086	)		-
Collateral for reclamation bonds		(9,550	)		-			-
Capital contributions from partners		-			12			28
Distributions to partners		-			(22,777	)		(36,843	)
Distributions to noncontrolling interest		-			-			(4,901	)
Net cash from financing activities		2,309			(22,772	)		(947	)
NET CHANGE IN CASH		(888	)		945			2,143
CASH, beginning of the year		3,977			3,032			889
CASH, end of the year	$	3,089		$	3,977		$	3,032

See accompanying notes to consolidated financial statements. 

F-6 

OXFORD RESOURCE PARTNERS, LP AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

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

NOTE 1:   ORGANIZATION AND PRESENTATION

Basis of Presentation and Principles of Consolidation

The accompanying consolidated financial statements include the accounts and operations of the Partnership and its consolidated subsidiaries and are prepared in conformity with accounting principles generally accepted in the United States of America (“US GAAP”).

Significant Relationships Referenced in Notes to Consolidated Financial Statements

● “We,”“us,” “our,” or the “Partnership” means the business and operations of Oxford Resource Partners, LP, the parent entity, as well as its consolidated subsidiaries.

● Our “GP” means Oxford Resources GP, LLC, the general partner of Oxford Resource Partners, LP.

Organization

We are a low-cost producer of high-value thermal coal and 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. These coal reserves are mined by our subsidiaries, Oxford Mining Company, LLC (“Oxford Mining”), Oxford Mining Company - Kentucky, LLC and Harrison Resources, LLC (“Harrison Resources”).

We are managed by our GP and all executives, officers and employees who provide services to us are employees of our GP. Charles C. Ungurean, the President and Chief Executive Officer of our GP and a member of our GP’s board of directors (“Mr. C. Ungurean”), and Thomas T. Ungurean, a former officer of our GP (“Mr. T. Ungurean”), are the co-owners of one of our limited partners, C&T Coal, Inc. (“C&T”).

AIM Oxford Holdings, LLC (“AIM Oxford”) and C&T held 65.81% and 33.49%, respectively, of the ownership interests in our GP with the remaining ownership interests therein being a 0.47% ownership interest held by Daniel M. Maher, our Senior Vice President, Chief Legal Officer and Secretary, and a 0.23% ownership interest held by Jeffrey M. Gutman, a former officer of our GP. As of December 31, 2013, AIM Oxford, C&T and our GP had ownership in the Partnership of 35.33%, 17.98% and 1.99%, respectively. The remaining 44.70% was held by the general public and participants in our Long-Term Incentive Plan (our “LTIP”).

We have a 51% ownership interest in Harrison Resources and also have control for purposes of US GAAP. As a result, we consolidate all of Harrison Resources’ accounts with all material intercompany transactions and balances being eliminated in our consolidated financial statements. The remaining 49% ownership interest in Harrison Resources that we do not own is reflected as “noncontrolling interest” in our consolidated balance sheets and statements of operations. See Note 14.

NOTE 2:   SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

Use of Estimates

Our financial statements are prepared in accordance with US GAAP. The preparation of these financial statements require management to make estimates and assumptions that affect the reported amounts of assets, liabilities, revenues and expenses, as well as the disclosures of contingent assets and liabilities (if any).

The most significant policies requiring the use of management estimates and assumptions relate to collectability of accounts receivable, useful lives of fixed assets, valuation of coal reserves, amortization calculations using the units-of-production method, reserve estimates of coal reserves, evaluations of asset impairment, recoverability of advance royalties, useful lives of intangible assets, and estimates of future reclamation and mine closure costs. The estimates and assumptions that we use are based upon our evaluation of the relevant facts and circumstances as of the date of the financial statements. Actual results could differ significantly from those estimates.

F-7 

OXFORD RESOURCE PARTNERS, LP AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

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

NOTE 2:   SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (continued)

Liquidity

The accompanying consolidated financial statements have been prepared assuming that we will continue as a going concern.  We have incurred net losses of $23,700, $26,053 and $8,329 for the years ended December 31, 2013, 2012, and 2011, respectively, resulting in an accumulated deficit of $10,998 at December 31, 2013. We have managed our liquidity for the year ended December 31, 2013, with $9,676 of cash flows provided from operations and $2,309 of cash flows provided from financing activities. As of December 31, 2013, our available liquidity was $8.2 million, which consisted of $3.1 million in cash on hand and $5.1 million of borrowing capacity under our credit facilities.

Should we have difficulty meeting our forecasts, this could have an adverse effect on our liquidity position. Management has taken the following actions to improve its liquidity position:

● restructured our Illinois Basin operations (see Note 3);

● aligned our coal production with our committed coal sales and reduced costs by temporarily idling production at two Northern Appalachian mines and eliminating approximately 50 positions;

● reduced capital expenditures; and

● acquired a strategically located coal preparation plant next to a significant customer that will reduce coal transportation costs.

Through the aforementioned actions, management expects to be able to achieve its forecasted results for the year ending December 31, 2014. However, there can be no assurance that our cash flows will be sufficient to allow us to continue as a going concern if we are unable to meet our projections.

Cash and Restricted Cash

Cash and restricted cash consist of cash held with reputable depository institutions. Cash and restricted cash are stated at cost, which approximates fair market value. At times, such deposits may be in excess of the FDIC insurance limit. We have not experienced any losses in such accounts and believe we are not exposed to any significant credit risk relating to such amounts.

We had restricted cash related to Harrison Resources of $3,969 and $3,929 as of December 31, 2013 and 2012, respectively, which are included in our consolidated balance sheets as “other long-term assets.” Harrison Resources’ cash, which is deemed to be restricted due to the limitations of its use for Harrison Resources’ operations, primarily relates to funds set aside for future reclamation obligations. See the Noncontrolling Interest section of this Note 2 and Note 14.

Allowance for Doubtful Accounts

We establish an allowance for losses on accounts receivable when it is probable that all or part of an outstanding balance will not be collected. Our management regularly reviews the probability that a receivable will be collected and establishes or adjusts the allowance as necessary. There was no allowance for doubtful accounts as of December 31, 2013 and 2012.

Inventory

Inventory consists of coal that has been completely uncovered or that has been removed from the pit and stockpiled for crushing, washing or shipment to customers. Inventory also consists of supplies, spare parts and fuel. Inventory is valued at the lower of average cost or market. The cost of coal inventory includes certain operating expenses including overhead and stripping costs incurred during the production phase, which commences when saleable coal, beyond a de minimis amount, is produced.

F-8 

OXFORD RESOURCE PARTNERS, LP AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

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

NOTE 2: SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (continued)

Property, Plant and Equipment

Property, plant and equipment are recorded at cost. Expenditures that extend the useful lives of existing plant and equipment are capitalized. Maintenance and repairs that do not extend the useful life or increase productivity are charged to operating expense as incurred. Plant and equipment are depreciated principally on the straight-line method over the estimated useful lives of the assets based on the following schedule:

	Years
Buildings and tipple		25	-	39
Machinery and equipment		1	-	12
Vehicles		5	-	7
Furniture and fixtures		3	-	7
Railroad siding			7

We acquire our coal reserves through purchases or leases. We deplete our coal reserves using the units-of-production method on the basis of tonnage mined in relation to total estimated recoverable tonnage with residual surface values classified as land. As of December 31, 2013 and 2012, all of our Northern Appalachian reserves were attributed to mine complexes engaged in mining operations or leased to third parties. As of December 31, 2013, all Illinois Basin mining activities had been idled. Management would consider offers for the remaining coal reserves and/or facilities related to the Illinois Basin operations.

Exploration expenditures are charged to operating expense as incurred and include costs related to locating coal deposits and the drilling and evaluation costs incurred to assess the economic viability of such deposits. Costs incurred in areas outside the boundary of known coal deposits and areas with insufficient drilling to qualify as proven and probable reserves are also expensed as exploration costs.

Once management determines there is sufficient evidence that the expenditure will result in a future economic benefit to the Partnership, the costs are capitalized as mine development costs. Capitalization of mine development costs continues until more than a de minimis amount of saleable coal is extracted from the mine. Amortization of these mine development costs is then initiated using the units-of-production method based upon the total estimated recoverable tonnage.

Long-Lived Assets and Asset Impairment

Long-lived assets, such as property, plant and equipment, coal reserves, mine development costs and intangible assets, are reviewed for impairment whenever events or changes in circumstances indicate that the carrying amount of an asset or asset group may not be recoverable. Recoverability is measured by comparing the projected future cash flows from use and disposition of assets with the carrying amounts of those assets. When the sum of projected cash flows is less than the carrying amount, impairment losses are indicated. If the fair value of the assets is less than the carrying amount thereof, an impairment loss is recognized. In determining such impairment losses, discounted cash flows or asset appraisals are utilized to determine the fair value of the assets being evaluated. Assets held for sale are reported at the lower of the carrying amount or fair value less costs to sell, and are no longer depreciated.

Also, in certain situations, expected mine lives are shortened because of changes to planned operations. When that occurs and it is determined that the mine’s underlying costs are not recoverable in the future, reclamation and mine closure obligations are accelerated by accelerating the depletion rate. To the extent it is determined that an asset’s carrying value will not be recoverable during a shorter mine life, the asset is written down to its recoverable value. There were no indicators of impairment present during the years ended December 31, 2013 and 2011. See Note 3 for discussion of impairment expenses in 2012.

F-9 

OXFORD RESOURCE PARTNERS, LP AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

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

NOTE 2: SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (continued)

Advance Royalties

A substantial portion of our reserves are leased. Advance royalties are advance payments made to lessors under terms of lease agreements that are typically recoupable through an offset or credit against royalties payable on future production. We write-off advance royalties when recoverability is no longer probable based on future mining plans.

Deferred Financing Costs

We capitalize costs incurred in connection with the establishment of credit facilities and amortize such costs to interest expense over the term of the credit facilities using the effective interest method.

Financial Instruments and Derivative Financial Instruments

Our financial instruments include cash and restricted cash, accounts receivable, accounts payable, fixed rate debt and variable rate debt. In 2012, we also had an interest rate swap agreement. We do not hold or purchase financial instruments or derivative financial instruments for trading purposes.

Our financial instruments include fixed price forward contracts for diesel fuel. Our risk management policy allows us to purchase up to 80% of our unhedged diesel fuel gallons on fixed price forward contracts. These contracts meet the normal purchases and sales exclusion and therefore are not accounted for as derivatives. These forward fuel contracts usually have a term of one year or less, and we take physical delivery of all the fuel supplied under these contracts except in the case of one Illinois Basin contract which was modified.

Warrants

In conjunction with our refinancing in June 2013, certain of the second lien lenders and lender affiliates received warrants entitling them to purchase common and subordinated units under a freestanding contract. Pursuant to Financial Accounting Standards Board's Accounting Standards Board's Codification Topic 470-20, “Debt With Conversion and Other Options” (ASC 470-20), freestanding contracts that are settled in a company’s own stock, including common and subordinated unit warrants, are to be designated as an asset, liability or equity instrument. Both the common and subordinated unit warrants were determined to be liabilities and were recorded at fair value as determined using the Black-Scholes Pricing Model. ASC 470-20 further requires that the warrants' fair value be remeasured each reporting period, with the change in fair value being reported in the consolidated statements of operations. Fair value determinations prepared using the Black-Scholes Pricing Model require assumptions related to interest rates, unit price, exercise price, term and volatilities.

Intangible Assets

We have recorded intangible assets associated with certain customer relationships at fair value. These balances arose from the purchase accounting for our acquisition of Oxford Mining and its subsidiaries. These intangible assets are being amortized over their expected useful lives and are recorded in “intangible assets, net” in our consolidated balance sheets. See Note 7 for further details.

Reclamation and Mine Closure Costs

Our reclamation and mine closure costs arise from the Surface Mining Control and Reclamation Act (“SMCRA”) and similar state statutes, which require that mine property be restored in accordance with specified standards and an approved reclamation plan. Our reclamation and mine closure costs are recorded initially at fair value based on the assumption that all work will be performed by third-party contractors. We estimate reclamation and mine closure costs using the end of mine life method. The end of mine life method estimates the liability based on the costs to reclaim the last pit(s) once the mine is no longer producing coal. This liability is amortized over the tons expected to be recovered over the productive life of the mine.

To determine the fair value of our reclamation and mine closure costs, we calculate on a mine-by-mine basis the present value of estimated reclamation cash flows. This process requires us to estimate the acreage subject to reclamation, estimate future reclamation costs, and make assumptions regarding the mine’s productivity. These cash flows are discounted at a credit-adjusted, risk-free interest rate based on U.S. Treasury bonds with a maturity similar to the expected lives of the mines.

When the liability is initially established, the offset is capitalized to the mine development asset. Over time, the reclamation and mine closure cost liability is accreted to its present value, and the capitalized cost is depleted using the units-of-production method for the related mine. If the assumptions used to estimate the reclamation and mine closure cost liability do not materialize as expected or regulatory changes occur, reclamation costs or obligations to perform reclamation and mine closure activities could be materially different than initially estimated. At least annually, we review our reclamation liability and make adjustments for permit changes, cost revisions, changes to mining plans and the timing of expenditures. See Note 9.

F-10 

OXFORD RESOURCE PARTNERS, LP AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

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

NOTE 2: SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (continued)

Income Taxes

As a partnership, we are not a taxable entity for federal or state income tax purposes; the tax effect of our activities passes through to our unitholders. Therefore, no provision or liability for federal or state income taxes is included in our financial statements. Net income (loss) for financial statement purposes may differ significantly from taxable income (loss) reportable to our unitholders as a result of timing or permanent differences between financial reporting under US GAAP and the regulations promulgated by the Internal Revenue Service.

Revenue Recognition

Revenue from coal sales is recognized and recorded when shipment or delivery to the customer has occurred, prices are fixed or determinable, and the title or risk of loss has passed. Coal sales prices are subject to premiums and reductions based on variations in coal quality delivered versus specifications in our coal supply contracts, but such adjustments are typically confirmed in a matter of days. Risk of loss typically transfers to the customer at the mine or dock, when the coal is loaded on the rail, barge, or truck.

Other revenue consists primarily of clay and limestone sales, royalty income, service fees, and other miscellaneous revenue. Clay and limestone sales relate to material we recover during the coal mining process and sell to third parties. Royalty income relates to underground coal reserves that we sublease to a third party mining company. For the years ended 2013, 2012 and 2011, we received royalties of $8, $1,496 and $3,202, respectively. In 2012, we received an advance payment of $2.2 million for these royalties in exchange for a significant reduction in the amount of the overriding royalty going forward. Service fees are earned for operating a coal unloading facility, providing river barge loading services, and hauling ash. Periodically, we recognize miscellaneous revenue related to lost coal claims that result from granting third-party right-of-way access through small portions of various mine complexes.

Below-Market Coal Sales Contracts

Our below-market coal sales contracts were acquired through the Phoenix Coal acquisition in 2009 and represent contracts for which the prevailing market price for the specified coal was in excess of the contract price. The fair value was based on discounted cash flows resulting from the difference between the below-market contract price and the prevailing market price at the date of acquisition. The fair value adjustments are amortized into coal sales on the basis of tons shipped over the terms of the respective contracts. Amortization of these below-market contracts included in revenue was $60, $623 and $939 for the years ended December 31, 2013, 2012 and 2011, respectively. The current portion of the net carrying value of our below-market coal sales contracts was reflected in our consolidated balance sheets as “other current liabilities.” No such amounts remained at December 31, 2013.

Equity-Based Compensation

We account for equity-based awards in accordance with applicable guidance, which establishes standards of accounting for transactions in which an entity exchanges its equity instruments for goods or services. Equity-based compensation expense is recorded based upon the fair value of the award at grant date. The fair value of our LTIP units is determined based on the closing sales price of our units on the New York Stock Exchange on the grant date. The related expense is recognized on a straight-line basis over the corresponding vesting period. See Note 12.

Noncontrolling Interest

US GAAP requires noncontrolling interests to be reported as a separate component of equity. The amount of net income attributable to the noncontrolling interests is recorded in “net income attributable to noncontrolling interest” in our consolidated statements of operations. See Note 14.

F-11 

OXFORD RESOURCE PARTNERS, LP AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

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

NOTE 2: SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (continued)

Earnings (Losses) Per Unit

For purposes of our earnings per unit calculation, we apply the two class method. All outstanding limited partner units and general partner units share pro rata in income (loss) allocations and distributions, but only our general partner has voting rights. Limited partner units are further segregated into common units and subordinated units.

Limited Partner Units: Basic earnings (losses) per unit are computed by dividing net income (loss) attributable to limited partners by the weighted average units outstanding, including unexercised participating warrants, during the reporting period. Diluted earnings (losses) per unit are computed similar to basic earnings (losses) per unit except that the weighted average units outstanding and net income (loss) attributable to limited partners are increased to include phantom units that have not yet vested and that will convert to limited partnership units upon vesting. In periods of a loss, the phantom units are anti-dilutive and therefore not included in the earnings (losses) per unit calculation.

General Partner Units: Basic earnings (losses) per unit are computed by dividing net income (loss) attributable to our GP by the weighted average units outstanding, including unexercised participating warrants, during the reporting period. Diluted earnings (losses) per unit for our GP are computed similar to basic earnings (losses) per unit except that the net income (loss) attributable to the general partner units is adjusted for the dilutive impact of the phantom units. In periods of a loss, the phantom units are anti-dilutive and therefore not included in the earnings (losses) per unit calculation.

New Accounting Standards Issued

There were various updates recently issued, most of which represented technical corrections to the accounting literature or application to specific industries. We do not believe that the adoption of the guidance provided by these updates will have a material impact on our consolidated financial statements.

Reclassifications

Certain prior-year amounts have been reclassified in our consolidated balance sheet as of December 31, 2012. Payments due on the term note of $6 million have been reclassified from “long-term debt” to “current portion of long-term debt.”

Certain prior-year amounts have been reclassified in our consolidated statements of cash flows to conform with current-year classifications. These reclassifications are to reclassify “change in restricted cash” in “Cash Flows From Investing Activities” to “restricted cash” in “Cash Flows From Operating Activities.” 

NOTE 3: IMPAIRMENT AND RESTRUCTURING EXPENSES

In March 2012, we received a termination notice from a customer related to an 0.8 million ton per year coal supply contract fulfilled from our Illinois Basin operations. In response, we idled one Illinois Basin mine and the related preparation plant, closed our Illinois Basin lab, reduced operations at two other mines, terminated a significant number of employees and substituted purchased coal for mined coal on certain sales contracts. Operations at the two remaining mines varied to best manage strip ratio impacts and other costs through early December 2013, at which time all production was discontinued. As of December 31, 2013, we have sold or redeployed almost all of the Illinois Basin equipment to our Northern Appalachian operations. 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 to purchase the remaining coal reserves and/or facilities related to our Illinois Basin operations.

Impairment Expenses

As a result of the restructuring described above, we recorded asset impairment expenses of $12.8 million during 2012. These non-cash expenses related to coal reserves, mine development assets and certain mining equipment (the “Impaired Assets”). No such expenses were recorded in the year ended December 31, 2013.

F-12 

OXFORD RESOURCE PARTNERS, LP AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

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

NOTE 3: IMPAIRMENT AND RESTRUCTURING EXPENSES (continued)

In determining our impairment expenses, we utilized market prices for similar assets and discounted projected future cash flows to determine the fair value of the Impaired Assets. Our discounted projected future cash flows were based on financial forecasts developed internally for planning purposes. These projections incorporated certain assumptions, including future costs and sales trends, estimated costs to sell and our expected net realizable values for the Impaired Assets. As of December 31, 2012, the Impaired Assets that we planned to sell, and were no longer in production, were presented separately as current assets held for sale in our consolidated balance sheet. Such Impaired Assets were recorded at carrying value, after taking into account the impairment. The Impaired Assets were not depreciated or amortized during the last nine months of 2012 and the first three months of 2013. Assets held for sale totaling $6.1 million that were not sold as of March 31, 2013 were reclassified from assets held for sale to machinery and equipment at that date.

Restructuring Expenses

Restructuring expenses related to our Illinois Basin operations totaled $1.8 and $2.9 million for the years ended December 31, 2013 and 2012, respectively. These expenses included termination costs for approximately 200 employees in 2012, and 35 employees in 2013, professional and legal fees and transportation costs associated with moving idled Illinois Basin equipment to our Northern Appalachian operations. In addition, we terminated one coal lease and wrote off the related asset in the second quarter of 2013. We expect to incur $0.1 million of additional costs during 2014 as we complete the restructuring. The liabilities related to the restructuring are included in “other current liabilities” in our consolidated balance sheets as of December 31, 2013 and 2012.

Restructuring accrual activity, combined with a reconciliation to “impairment and restructuring expenses” as set forth in our consolidated statements of operations, is summarized as follows:

	As of December 31, 2012		For the Twelve Months Ended December 31, 2013					As of December 31, 2013
	Liability		Expense		Payments			Liability
Severance and other termination costs	$	405	$	534	$	(535	)	$	404
Professional and legal fees		18		26		(44	)		-
Equipment relocation costs		20		495		(263	)		252
Coal lease termination costs		-		23		(23	)		-
Total cash restructuring expenses	$	443	$	1,078	$	(865	)	$	656

F-13 

OXFORD RESOURCE PARTNERS, LP AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

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

NOTE 3: IMPAIRMENT AND RESTRUCTURING EXPENSES (continued)

The following table summarizes the total impairment and restructuring expenses expected to be incurred over the course of the restructuring:

	Expenses
	For the Twelve Months Ended December 31, 2013		Incurred Through December 31, 2013		Total Expected Expenses
Cash:
Severance and other termination costs	$	534	$	1,887	$	1,887
Professional and legal fees		26		1,021		1,021
Equipment relocation costs		495		1,044		1,178
Coal lease termination costs		23		23		23
Total cash restructuring expenses		1,078		3,975		4,109
Non-cash:
Coal lease termination costs		683		683		683
Asset impairment		-		12,753		12,753
Total non-cash restructuring expenses		683		13,436		13,436
Total impairment and restructuring expenses	$	1,761	$	17,411	$	17,545

NOTE 4: INVENTORY

Inventory consisted of the following:

	As of December 31,
	2013		2012
Coal	$	5,957	$	5,609
Fuel		1,879		1,893
Spare parts and supplies		6,004		5,052
Total	$	13,840	$	12,554

F-14 

OXFORD RESOURCE PARTNERS, LP AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

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

NOTE 5: PROPERTY, PLANT AND EQUIPMENT, NET

Property, plant and equipment, net of accumulated depreciation, depletion and amortization, consisted of the following:

	As of December 31,
	2013			2012
Property, plant and equipment, gross:
Land	$	3,016		$	2,947
Coal reserves		49,574			53,376
Mine development costs		58,077			46,176
Buildings and tipple		1,957			1,957
Machinery and equipment		202,663			195,321
Vehicles		4,522			4,488
Furniture and fixtures		1,584			1,518
Railroad sidings		160			160
Total property, plant and equipment, gross		321,553			305,943
Less: accumulated depreciation, depletion and amortization		(177,127	)		(147,460	)
Total property, plant and equipment, net	$	144,426		$	158,483

The amounts of depreciation expense related to owned and leased fixed assets, depletion expense related to owned and leased coal reserves, amortization expense related to mine development costs and amortization expense related to intangible assets for the respective years are as follows:

	For the Year Ended December 31,
	2013		2012		2011
Depreciation	$	30,786	$	34,276	$	37,022
Depletion		4,513		4,869		5,697
Mine development amortization		12,528		11,783		8,913
Intangible asset amortization(1)		254		242		273
	$	48,081	$	51,170	$	51,905

(1) See Note 7.

In June 2013 and April 2012, we completed the sale of certain oil and gas rights and land in eastern Ohio for $6.1 million and $6.3 million, respectively, which is recorded in “(gain) loss on disposal of assets, net” in our consolidated statement of operations for the years ended December 31, 2013 and 2012. As part of these transactions, we retained royalty rights equivalent to 20% of net revenue once the wells are producing. We expect royalty revenue to be generated from these rights starting in the first quarter of 2014, which royalty revenue will be recorded in “other revenue.”

F-15 

OXFORD RESOURCE PARTNERS, LP AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

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

NOTE 6: OPERATING LEASES

We lease certain operating facilities and equipment under non-cancelable lease agreements that expire on various dates through 2018. Generally, the lease terms range from three to ten years. As of December 31, 2013, aggregate lease payments under operating leases that have initial or remaining non-cancelable lease terms in excess of one year are set forth below:

For the years ending December 31,   2014	$	7,928
2015		5,947
2016		2,642
2017		651
2018		2

For the years ended December 31, 2013, 2012 and 2011, we incurred lease expenses of $8,591, $7,118 and $3,383, respectively.

We also entered into various coal reserve lease agreements under which advance royalty payments are made. Most of these advance royalty payments are recoupable against future royalty payments otherwise due based on production. Such payments are capitalized as “advance royalties” at the time of payment, and are recoupable through an offset or credit against royalties payable on future production.

NOTE 7: INTANGIBLE ASSETS

	As of December 31, 2013
	Estimated Remaining Life (years)		Cost		Accumulated Amortization		Net Carrying Value
Intangible assets
Customer relationships		13	$	3,315	$	2,127	$	1,188

	As of December 31, 2012
	Estimated Remaining Life (years)		Cost		Accumulated Amortization		Net Carrying Value
Intangible assets
Customer relationships		14	$	3,315	$	1,873	$	1,442

Customer relationships represent intangible assets that were recorded at fair value when we acquired Oxford Mining and its subsidiaries in August 2007. The net carrying value of our customer relationships is reflected in our consolidated balance sheets as “intangible assets, net.” We amortize these assets over the expected life of the respective customer relationships. Amortization related to customer relationships totaled $254, $242, and $273 for the years ended December 31, 2013, 2012 and 2011, respectively.

F-16 

OXFORD RESOURCE PARTNERS, LP AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

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

NOTE 7: INTANGIBLE ASSETS (continued)

Expected amortization of intangible assets will be approximately:

For the years ending December 31, 2014	$	227
2015		204
2016		183
2017		126
2018		84
Thereafter		364

We evaluate our intangible assets for impairment when indicators of impairment exist. For the years ended December 31, 2013, 2012 and 2011, there were no indicators of impairment present for our intangible assets.

NOTE 8: OTHER LONG-TERM ASSETS AND OTHER CURRENT LIABILITIES

Other long-term assets consisted of the following:

	As of December 31,
	2013		2012
Reclamation bond collateral(1)	$	9,582	$	-
Deferred financing costs, net(1)		7,644		2,061
Restricted cash		3,969		3,929
Deposits		1,526		1,070
Other		100		117
Total	$	22,821	$	7,177

Other current liabilities consisted of the following:

	As of December 31,
	2013		2012
Accrued interest and interest rate swap(2)	$	1,424	$	709
Accrued royalties		1,062		815
Other		971		967
Total	$	3,457	$	2,491

(1)	See Note 10.
(2)	See Note 11 regarding interest rate swap.

NOTE 9: RECLAMATION AND MINE CLOSURE COSTS

As previously indicated, our reclamation and mine closure costs arise from SMCRA and similar state statutes, which require that mine property be restored in accordance with specified standards and an approved reclamation plan. The required reclamation activities to be performed are outlined in our mining permits. These activities include reclaiming the pit and support acreage, as well as stream mitigation.

As of December 31, 2013, our liability for reclamation and mine closure costs totaled $31.7 million, including amounts reported as current liabilities. While the precise amount of these future costs cannot be determined with certainty, we estimate that, as of December 31, 2013, the aggregate undiscounted cost of final reclamation and mine closure is $39.7 million.

F-17 

OXFORD RESOURCE PARTNERS, LP AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

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

NOTE 9: RECLAMATION AND MINE CLOSURE COSTS (continued)

Activities affecting the liability for reclamation and mine closure costs for the respective years are as follows:

	Year Ended December 31,
	2013			2012
Beginning balance	$	29,013		$	21,789
Accretion expense		2,293			1,567
Payments		(8,656	)		(8,966	)
Revisions in estimated cash flows		9,004			14,623
Total reclamation and mine closure costs		31,654			29,013
Less current portion		(5,996	)		(3,869	)
Noncurrent liability	$	25,658		$	25,144

In 2013, the revisions in discounted estimated cash flows resulted in a net increase in the reclamation and mine closure costs of $9.0 million. Of this amount, $3.7 million related to four new mines, $4.0 million related to reclamation work in progress at recently closed mines and the remaining $1.3 million related to updated cost estimates for pond removal, grading and water treatment.

In 2012, the revisions in discounted estimated cash flows resulted in a net increase in the reclamation and mine closures costs of $14.6 million. Of this amount, $5.7 million related to eight new mines, $3.6 million related to reclamation work in progress at recently closed mines and $1.5 million related to estimated closing costs and timing for two mines being closed earlier than anticipated, with the remaining $3.8 million due to revisions to estimates of expected costs. The accelerated closures are a result of the restructuring plan for our Illinois Basin operations, which we began implementing in the first quarter of 2012, as further discussed in Note 3.

Adjustments to the liability for reclamation and mine closure costs due to such revisions generally result in corresponding adjustments to the related mine development assets for active and new mines.

NOTE 10: LONG-TERM DEBT

Debt consisted of the following:

	As of December 31,
	2013			2012
Credit facilities:
First lien debt:
Term loan	$	69,321		$	45,000
Revolving line of credit		19,500			92,000
Second lien debt:
Term loan		70,862			-
Other obligations		3,593			7,527
Total debt		163,276			144,527
Less current portion		(7,901	)		(102,970	)
Long-term debt	$	155,375		$	41,557

Credit Facilities Generally

In connection with our initial public offering in July 2010, we entered into an agreement for our credit facility (our “2010 Credit Agreement”) which provided for a $115 million revolving credit line that matured in July 2013 and a $60 million term loan that would have matured in July 2014. We were required to make quarterly principal payments of $1.5 million on the term loan that commenced in September 2010 and continue until maturity when the remaining balance was to be paid. Borrowings under our 2010 Credit Agreement bore interest at a variable rate per annum equal to, at our option, the London Interbank Offered Rate (“LIBOR”) or the Base Rate plus the Applicable Margin (Base Rate and Applicable Margin are defined in our 2010 Credit Agreement).

F-18 

OXFORD RESOURCE PARTNERS, LP AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

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

NOTE 10: LONG-TERM DEBT (continued)

In June 2012, we executed an amendment to our 2010 Credit Agreement which was applicable for the remaining term. The amendment (i) modified the leverage ratio, (ii) authorized the sale of certain Kentucky assets, and (iii) allowed for quarterly distributions at specified minimum levels or at higher levels as long as specified liquidity thresholds were maintained. In connection with the amendment, we paid the consenting lenders a non-refundable amendment fee equal to 0.50% of their then outstanding loan commitments.

In June 2013, we closed on $175 million of credit facilities that replaced and was used to pay our 2010 Credit Agreement borrowings in full. These facilities include (i) a first lien credit facility consisting of a $75 million term loan and a $25 million revolver under a financing agreement (the “First Lien Financing Agreement”) and (ii) a second lien credit facility consisting of a $75 million term loan (with an option for an additional $10 million term loan if requested by us and approved by the issuing second lien lender) under a financing agreement (the “Second Lien Financing Agreement,” and collectively with the First Lien Financing Agreement, the “Financing Agreements”).

The first lien credit facility matures in September 2015 with an option to extend to June 2016, and the second lien credit facility matures in December 2015 with an option to extend to September 2016, if certain conditions are met. As of December 31, 2013, the blended cash interest rate for both credit facilities was 9.53%. The Financing Agreements contain customary financial and other covenants, and also preclude making unitholder distributions during the term of the credit facilities. Borrowings under the credit facilities are secured by substantially all of our assets. Proceeds of the credit facilities were used to retire our previous revolving credit line and term loan under our 2010 Credit Agreement, to cash collateralize letters of credit and to pay fees and expenses related to the credit facilities.

As of December 31, 2013, we were in compliance with all covenants under the terms of the Financing Agreements.

Warrants

In conjunction with the Second Lien Financing Agreement, certain lenders and lender affiliates received warrants entitling them to purchase 1,955,666 common units and 1,814,185 subordinated units at $0.01 per unit. The warrants participate in distributions whether or not exercised. During the five-year term for exercise of the warrants, the warrant exercise price and number of units will be adjusted for unit splits or reverse splits, such that the economics of the warrants remain unchanged. These warrants are freestanding financial instruments, within the scope of ASC 480, Distinguishing Liabilities from Equity, since they are detachable from the Second Lien Financing Agreement. The warrants, classified as a liability, were recorded at their fair value of $7.9 million at issuance. The warrants are subsequently marked to fair value with the change in fair value reported in earnings. The fair value assigned to the warrants at issuance was recorded as a debt discount, reducing the outstanding debt balance. This discount will be amortized through interest expense over the life of the second lien credit facility using the effective interest method. For the year ended December 31, 2013, the fair value of the warrants decreased $3.3 million. See Note 11 for fair value disclosures.

First Lien Credit Facility

As of December 31, 2013, we had a term loan of $69.3 million outstanding under the first lien credit facility. We are obligated to make quarterly principal payments of $1.3 million commencing in June 2014, until repayment of the then outstanding balance at maturity. Borrowings on the term loan bear interest at a variable rate per annum equal to, at our option, the London Interbank Offered Rate (“LIBOR”) (floor of 1.5%) plus 6.75% or the Reference Rate (as defined in the First Lien Financing Agreement) (floor of 3.00%) plus 6.25%. As of December 31, 2013, the first lien term loan had a cash interest rate of 8.25%, consisting of LIBOR of 1.5% plus 6.75%.

F-19 

OXFORD RESOURCE PARTNERS, LP AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

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

NOTE 10: LONG-TERM DEBT (continued)

The first lien credit facility also includes a $25 million revolving credit facility under which $19.5 million was outstanding as of December 31, 2013. Of this amount, $9.6 million is used to collateralize reclamation bonds. The revolving credit facility bears interest at the same rates as the term loan under the first lien credit facility. As of December 31, 2013, the balance outstanding on the revolving credit facility had a weighted average cash interest rate of 8.76%, consisting of either LIBOR of 1.5% plus 6.75% or the Reference Rate of 3.25% plus 6.25%. As of December 31, 2013, we had $5.1 million of borrowing capacity available on the revolving credit facility.

The Financing Agreements require mandatory prepayment of principal with proceeds from certain events. During the year ended December 31, 2013, we paid down $5.7 million of the first lien term loan with proceeds from the sale of oil and gas rights in late June 2013 and the granting of a pipeline right-of-way to a third party in September 2013.

Second Lien Credit Facility

A portion of the $75 million of principal associated with the term loan issued under the second lien credit facility was allocated to the warrants in an amount equal to their fair value at issuance of $7.9 million. The value allocated to the warrants was recorded as a debt discount, with the remaining $67.1 million assigned to the term loan. The debt discount will be amortized to interest expense over the life of the second lien credit facility using the effective interest method.  Amortization of the debt discount totaled $1.5 million for the year ended December 31, 2013.

We are obligated to make quarterly principal payments of $0.2 million commencing in June 2014, until repayment of the then outstanding balance at maturity. The term loan under the second lien credit facility bears cash interest at a variable rate per annum equal to, at our option, LIBOR (floor of 1.25%) plus 9.75% or the Reference Rate (as defined in the Second Lien Financing Agreement) (floor of 3.00%) plus 11.75%. As of December 31, 2013, the second lien credit facility term loan had a cash interest rate of 11.00%, consisting of LIBOR of 1.25% plus 9.75%.

The second lien credit facility also provides for “PIK Interest” (paid-in-kind interest as defined in the Second Lien Financing Agreement) at the rate of 5.75%. PIK Interest is added quarterly to the then outstanding principal amount of the term loan as additional principal obligations. PIK Interest totaled $2.3 million for the year ended December 31, 2013.

As of December 31, 2013, the outstanding balance on the second lien term loan was $70.9 million. This amount represents the principal balance of $75.0 million, plus PIK Interest of $2.3 million, net of the unamortized debt discount of $6.4 million. 

Other Obligations

CONSOL Coal Reserves – In August 2010, Harrison Resources acquired coal reserves from CONSOL Energy, through one of its subsidiaries, in exchange for a down payment of $850 and a note payable in an original face amount of $13,458 that matures three years from the date of issuance to Harrison Resources of the permit to mine such reserves. This note is payable in three annual installments of $5,383, $5,383 and $2,692 commencing with the issuance of such permit in September 2012. This note has no stated interest rate; therefore, the difference between the face amount and the imputed amount was recorded as a discount using an imputed interest rate of 5.5% and is being amortized into interest expense using the effective interest method. As of December 31, 2013 and 2012, the outstanding balance on the CONSOL #3 loan was $2,584 and $7,508, respectively.

AEP Conesville Coal Preparation Plant – In April 2013, Oxford Conesville, LLC, a wholly-owned subsidiary of Oxford Mining, acquired the assets of the AEP Conesville coal preparation plant for $488 in cash, a $1,000 note at the rate of 5.00% and the assumption of the reclamation obligation. The note is payable in two installments payments of $500 due on April 5, 2014 and December 31, 2014.

F-20 

OXFORD RESOURCE PARTNERS, LP AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

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

NOTE 10: LONG-TERM DEBT (continued)

Other Note Payable – We acquired coal reserves from an individual with payments due of $5 per year for ten years at no stated interest rate. The obligation matures in April 2015. The difference between the face amount and the imputed amount was recorded as a discount using an imputed interest rate of 6.75% and is being amortized into interest expense using the effective interest method.

Debt Maturity Table

The total debt of the Partnership matures as follows:

During the years ending December 31, 2014	$	7,901
2015		155,375
	$	163,276

Deferred Financing Costs

During the year ended December 31, 2013, net deferred financing costs totaling $0.8 million related to the credit facility under our 2010 Credit Agreement were written-off as interest expense and we capitalized $9.6 million of deferred financing costs related to our new credit facilities under the Financing Agreements.  These costs, included in “other long-term assets,” represent fees paid to lenders and advisors and for legal services. Amortization of deferred financing costs included in interest expense was $3,986, $2,175, and $1,600 for the year ended December 31, 2013, 2012 and 2011, respectively.

Selling, general and administrative expenses for 2013 included $0.7 million of fees paid to advisors and for legal services related to our credit facility refinancing, and $2.4 million of fees paid to lenders and advisors and for legal services related to the attempted refinancing of our credit facility under our 2010 Credit Agreement. There were no such expenses during the years ended December 31, 2012 and 2011.

NOTE 11: FAIR VALUE OF FINANCIAL INSTRUMENTS

We utilize fair value measurement guidance that, among other things, defines fair value, requires enhanced disclosures about assets and liabilities carried at fair value and establishes a hierarchical disclosure framework based upon the quality of inputs used to measure fair value. We have elected not to measure any additional financial assets or liabilities at fair value, other than those required to be recorded at fair value.

The financial instruments measured at fair value on a recurring basis are summarized below:

	Fair Value Measurements as of December 31, 2013
	Quoted Prices in Active Markets for Identical Liabilities		Significant Other Observable Inputs			Significant Unobservable Inputs
Description	(Level 1)		(Level 2)			(Level 3)
Warrants	$	-	$	(4,599	)	$	-

	Fair Value Measurements as of December 31, 2012
	Quoted Prices in Active Markets for Identical Liabilities		Significant Other Observable Inputs			Significant Unobservable Inputs
Description	(Level 1)		(Level 2)			(Level 3)
Interest rate swap agreement	$	-	$	(12	)	$	-

F-21 

OXFORD RESOURCE PARTNERS, LP AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

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

NOTE 11: FAIR VALUE OF FINANCIAL INSTRUMENTS (continued)

The interest rate swap agreement matured in the first quarter of 2013.

The warrants are fair valued at each balance sheet date using the Black-Scholes model. At December 31, 2013, the fair value of each warrant was $1.22, based on the following assumptions: spot price of $1.23 per unit, exercise price of $0.01 per unit, term of 4.5 years, volatility of 80% and a five-year treasury rate of 1.75%.

The following methods and assumptions were used to estimate the fair values of financial instruments for which the fair value option was not elected:

Cash and restricted cash, accounts receivable and accounts payable:  The carrying amount reported in the consolidated balance sheets for cash and restricted cash, accounts receivable and accounts payable approximates fair value due to the short maturity of these instruments.

Derivatives: The fair value of derivatives is established using a discounted cash flow analysis using primarily inputs that can be observed within financial markets, such as LIBOR rates.

Fixed rate debt:  The fair value of fixed rate debt is estimated using discounted cash flow analyses, based on current market rates for instruments with similar cash flows. As such, the fair value of fixed rate debt is considered level 2.

Variable rate debt:  The fair value of variable rate debt is estimated using discounted cash flow analyses, based on our best estimates of market rate for instruments with similar cash flows. As such, the fair value of variable rate debt is considered level 2.

The carrying amounts and fair values of financial instruments for which the fair value option was not elected are as follows:

	As of December 31, 2013				As of December 31, 2012
	Carrying Amount		Fair Value		Carrying Amount		Fair Value
Fixed rate debt	$	3,593	$	3,386	$	7,527	$	7,642
Variable rate debt		159,683		159,683		137,000		137,000

NOTE 12: LONG-TERM INCENTIVE PLAN

Under our LTIP, we recognize equity-based compensation expense over the vesting period of the units. These units are subject to conditions and restrictions as determined by our Compensation Committee, including continued employment or service. Historically, these units generally vested in equal annual increments over four years with accelerated vesting of the first increment in certain cases. Beginning in 2012, some of the units granted to executive officers vest based on specified performance criteria.

For the years ended December 31, 2013, 2012 and 2011, we recognized equity-based compensation expense of $1,441, $1,262 and $1,077, respectively. These amounts are included in selling, general and administrative expenses. As of December 31, 2013 and 2012, $2,150 and $1,843, respectively, of cost remained unamortized. We expect to recognize these costs using the straight-line method over a remaining weighted average period of 1.2 years as of December 31, 2013.

F-22 

OXFORD RESOURCE PARTNERS, LP AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

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

NOTE 12: LONG-TERM INCENTIVE PLAN (continued)

The following table summarizes additional information concerning our unvested LTIP units:

	Units			Weighted Average Grant Date Fair Value
Unvested balance at December 31, 2011		80,043		$	16.25
Granted		312,138			10.08
Issued		(71,066	)		9.68
Surrendered		(63,152	)		11.82
Unvested balance at December 31, 2012		257,963			11.67
Granted		438,990			3.98
Issued		(115,883	)		5.74
Surrendered		(21,886	)		13.59
Unvested balance at December 31, 2013		559,184			6.79

The value of LTIP units vested during the years ended December 31, 2013, 2012 and 2011 was $963, $944 and $908, respectively.

As of December 31, 2013, 2,056,075 units were authorized for issuance under our LTIP and 1,064,001 units remained available to be awarded.  In early 2014, an additional 750,000 units were authorized and 1,347,502 units were awarded.  Subsequent to these events, 468,148 units remained available to be awarded, assuming that all grants outstanding are settled with units without reduction for income tax withholding and that no future forfeitures occur.

F-23 

OXFORD RESOURCE PARTNERS, LP AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

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

NOTE 13: EARNINGS (LOSSES) PER UNIT

The computation of basic and diluted earnings (losses) per unit under the two class method for limited partner units and general partner units is presented as follows:

	For the Year Ended December 31,
	2013			2012			2011
Limited partner units
Average units outstanding:
Basic		22,776,481			20,711,952			20,641,127
Effect of equity-based compensation	N/A			N/A			N/A
Diluted		22,776,481			20,711,952			20,641,127
Net loss allocated to limited partners
Basic	$	(24,470	)	$	(26,273	)	$	(12,816	)
Diluted		(24,470	)		(26,273	)		(12,816	)
Net loss per limited partner unit
Basic	$	(1.07	)	$	(1.27	)	$	(0.62	)
Diluted		(1.07	)		(1.27	)		(0.62	)
General partner units
Average units outstanding:
Basic and diluted		423,618			422,609			421,038
Net loss allocated to general partner
Basic	$	(455	)	$	(535	)	$	(261	)
Diluted		(455	)		(535	)		(261	)
Net loss per general partner unit
Basic	$	(1.07	)	$	(1.27	)	$	(0.62	)
Diluted		(1.07	)		(1.27	)		(0.62	)
Anti-dilutive units (1) (2)		-			-			68,760
Distributions paid per unit:
Limited partners:
Common	$	-		$	1.5125		$	1.7500
Subordinated		-			0.6375			1.7500
General partner		-			1.0750			1.7500

(1) Anti-dilutive units are not used in calculating diluted average units.

(2) Unvested LTIP units are not dilutive units for the years ended December 31, 2013 and 2012.

Under the Partnership’s partnership agreement, arrearage amounts resulting from suspension of the common units distribution accumulate, while those related to the subordinated units do not. In the future if and as distributions are made for any quarter, the first priority is to pay the then minimum quarterly distribution to common unitholders (including the holders of common unit warrants). Any additional distribution amounts paid at that time are then paid to common unitholders (including the holders of common unit warrants) until their previously unpaid accumulated arrearage amounts have been paid in full. As of December 31, 2013, the total arrearage amount was $25.3 million. In the first quarter 2013, due to continued weakness in the coal markets, distributions related to the fourth quarter 2012 and going forward were suspended to further preserve liquidity. Distributions are also prohibited by the Financing Agreements as long as we have outstanding borrowings thereunder.

F-24 

OXFORD RESOURCE PARTNERS, LP AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

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

NOTE 14: NONCONTROLLING INTEREST

Harrison Resources, a limited liability company, was formed in March 2006 by Oxford Mining to acquire coal properties, develop mine sites and mine coal for sale to customers. Effective January 30, 2007, 49% of Harrison Resources was sold to CONSOL Energy and its ownership interest is held by one of its subsidiaries. Harrison Resources’ revenues, which are included in our consolidated statements of operations, were $34,100, $34,518 and $38,664 for the years ended December 31, 2013, 2012 and 2011, respectively. Oxford Mining has a services agreement with Harrison Resources under which we perform mining and reclamation services for agreed-upon per ton prices. Additionally, Oxford Mining has a broker agreement with Harrison Resources under which we market the coal.

Harrison Resources’ cash, which is deemed to be restricted, primarily relates to funds set aside for reclamation obligations in the amounts of $3,969 and $3,929 as of December 31, 2013 and 2012, respectively, and is included in our consolidated balance sheets as “other long-term assets.” Harrison Resources’ total net assets as of December 31, 2013 and 2012 were $10,140 and $7,641, respectively.

Noncontrolling interest, which represents the 49% of Harrison Resources owned by CONSOL Energy through one of its subsidiaries, consists of the following:

	For the Year Ended December 31,
	2013		2012
Beginning balance	$	3,744	$	2,989
Net income		1,225		755
Ending balance	$	4,969	$	3,744

NOTE 15: WORKERS’ COMPENSATION AND BLACK LUNG

We have no liabilities under state statutes and the Federal Coal Mine Health and Safety Act of 1969, as amended, to pay black lung benefits to eligible employees, former employees and their dependents. Under the Black Lung Benefits Revenue 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, with neither amount to exceed 4.4% of the gross sales price for the coal. For the years ended December 31, 2013, 2012 and 2011, we recorded $3.2 million, $3.6 million and $4.2 million, respectively, in our cost of coal sales related to this excise tax.

With regard to workers’ compensation, we are insured through state sponsored programs or an insurance carrier where there is no state sponsored program.

NOTE 16: RETIREMENT PLAN

We maintain a 401(k) plan for the benefit of our employees. For the years ended December 31, 2012 and 2011, we committed to and made an employer contribution at 4% of qualified wages totaling $1.9 million and $2.2 million, respectively. For the year ended December 31, 2013, we did not commit to make and are not making any discretionary employer contribution to the 401(k) plan.

F-25 

OXFORD RESOURCE PARTNERS, LP AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

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

NOTE 17: COMMITMENTS AND CONTINGENCIES

Coal Sales Contracts

We are committed under long-term contracts to sell coal that meets certain quality requirements at specified prices. Many of these prices are subject to cost pass-through or cost adjustment provisions that mitigate some risk from rising costs. Quantities sold under some of these contracts may vary from year to year within certain limits at the option of the customer or us. As of December 31, 2013, the remaining terms of our long-term contracts range from one to two years.

We received a contract termination notice in March 2012 from a customer of our Illinois Basin operations. This contract required us to supply the customer with 0.8 million tons of coal per year. Absent any termination thereof, the term of the contract continued until December 31, 2015. We believe that this customer's action was taken in bad faith, motivated by the combination of the price increase that had recently gone into effect and current coal market conditions. We are aggressively pursuing compensation for our damages through all appropriate legal measures.

Purchase Commitments

From time to time, we purchase coal from third parties in order to meet quality or delivery requirements under our customer contracts. We buy coal on the spot market, and the cost of that coal is dependent upon the market price and quality of the coal. We previously had a long-term purchase contract for 0.4 million tons of coal per year with a separate supplier who had asserted that the contract had terminated by its terms. We entered into a settlement agreement with the supplier in February 2013 under which the parties agreed to terminate the contract with the supplier making a one-time payment of $2.1 million to us.

Transportation

We depend upon barge, rail and truck transportation systems to deliver coal to our customers. We have a long-term rail transportation contract that has been amended and extended through March 31, 2015.

401(k) Plan

As of September 30, 2013, we satisfied the obligation to pay our GP for the purpose of funding our GP’s commitment to our 401(k) plan in the amount of $1.9 million related to plan and fiscal year ended December 31, 2012. For the year ended December 31, 2013, the GP made no commitment to fund an employer contribution to our 401(k) plan.

Surety and Performance Bonds

As of December 31, 2013, we had $37.0 million in surety bonds outstanding to secure certain reclamation obligations which were collateralized by cash of $9.6 million. Such cash collateral is included in “other long-term assets” on our consolidated balance sheet and “collateral for reclamation bonds” within financing activities on our consolidated statement of cash flows. Additionally, we had road bonds totaling $0.6 million and performance bonds totaling $2.1 million outstanding to secure contractual performance. We believe these bonds will expire without any claims or payments thereon and therefore will not have a material adverse effect on our financial position, liquidity or operations.

Legal

From time to time, we are involved in various legal proceedings arising in the ordinary course of business. While the ultimate resolution of these proceedings cannot be predicted with certainty, we believe that these claims will not have a material adverse effect on our financial position, liquidity or operations.

F-26 

OXFORD RESOURCE PARTNERS, LP AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

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

NOTE 17: COMMITMENTS AND CONTINGENCIES (continued)

Guarantees

Our GP and the Partnership guarantee certain obligations of our subsidiaries. We believe that these guarantees will expire without any liability to the guarantors, and therefore will not have a material adverse effect on our financial position, liquidity or operations.

NOTE 18: CONCENTRATION OF CREDIT RISK AND MAJOR CUSTOMERS

We have a credit policy that establishes procedures to determine creditworthiness and credit limits for customers. Generally, credit is extended based on an evaluation of the customer’s financial condition. Collateral is not generally required, unless credit cannot be established.

We market our coal principally to electric utilities, electric cooperatives, municipalities and industrial customers in Indiana, Kentucky, Michigan, Ohio, Pennsylvania and West Virginia. As of December 31, 2013 and 2012, accounts receivable from electric utilities totaled $19.6 million and $12.6 million, respectively, or 75.9% and 63.6% of total receivables, respectively. The following table shows the amount of sales to each customer (in each year where applicable, a “Major Customer”) which individually accounted for greater than 10% of sales in any of the years ended December 31, 2013, 2012 and 2011, with a portion of these sales being facilited by coal brokers.

	Revenues for the Year Ended December 31,
Customer	2013		2012		2011
	(in millions)
American Electric Power	$	146.3	$	128.8	$	139.7
First Energy		69.2		85.8		58.0
East Kentucky Power Cooperative		41.4		56.6		43.7
Big Rivers Electric		*		*		44.0

*Sales to this customer were less than 10% in the respective year.

Three Major Customers in 2013 and 2012, in the aggregate, represented 74.1% and 72.6%, respectively, of our total sales in the applicable year, and four Major Customers in 2011, in the aggregate, represented 71.3% of our total sales in that year. Three of the Major Customers in each of 2013 and 2012, in the aggregate, represented 81.5% and 67.9% of the outstanding accounts receivable at December 31, 2013 and 2012, respectively.

NOTE 19: RELATED PARTY TRANSACTIONS

In connection with our formation in August 2007, the Partnership and Oxford Mining entered into an administrative and operational services agreement (the “Services Agreement”) with our GP. The Services Agreement is terminable by either party upon thirty days’ written notice. Under the terms of the Services Agreement, our GP provides services through its employees to us and is reimbursed for all related costs incurred on our behalf. Our GP provides us with services such as general administrative and management, human resources, legal, information technology, finance and accounting, corporate development, real property, marketing, engineering, operations (including mining operations), geological, risk management and insurance services. Pursuant to the Services Agreement, the primary reimbursements to our GP were for costs related to payroll. Reimbursable costs under the Services Agreement totaling $624 and $3,442 were included in accounts payable as of December 31, 2013 and 2012, respectively.

We sell clay and small quantities of coal to Tunnell Hill Reclamation, LLC (“Tunnell Hill”), a company that is indirectly owned by Mr. C. Ungurean, Mr. T. Ungurean, and affiliates of AIM Oxford. We sold equipment to Tunnell Hill for $877 in 2012. Sales to Tunnell Hill were $385, $205 and $1,525 for the years ended December 31, 2013, 2012 and 2011, respectively. Accounts receivable from Tunnell Hill were $83 and a de minimis amount for the years ended December 31, 2013 and 2012, respectively.

F-27 

OXFORD RESOURCE PARTNERS, LP AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

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

NOTE 19: RELATED PARTY TRANSACTIONS (continued)

From time to time for business purposes, we charter the use of various airplanes from Zanesville Aviation located in Zanesville, Ohio. Additionally, C&T owns an airplane that it leases to Zanesville Aviation and Zanesville Aviation uses that airplane in providing charter services to its customers, including us at times. During the years of 2013, 2012 and 2011, we paid Zanesville Aviation an aggregate of $97, $146 and $178, respectively.

NOTE 20: SUPPLEMENTAL CASH FLOW INFORMATION

Supplemental cash flow information:

	For the Year Ended December 31,
	2013		2012		2011
Cash paid for:
Interest	$	12,258	$	10,739	$	6,976
Non-cash activities:
Coal reserves acquired with debt		-		307		-
Property and equipment acquired with debt		1,000		-		-
Reclamation and mine closure costs capitalized in mine development		8,927		16,011		12,278
Value of debt assigned to warrants		7,879		-		-
Market value of common units vested in LTIP		330		849		2,055

NOTE 21: SEGMENT INFORMATION

We operate in one business segment. We operate surface coal mines in Northern Appalachia and through December 2013 in the Illinois Basin and sell high-value thermal coal to utilities, industrial customers, municipalities and other coal-related entities primarily in the eastern United States. Our operating and executive management reviews and bases its decisions upon consolidated reports. Three of our operating subsidiaries extract coal utilizing surface-mining techniques and prepare it for sale to their customers. Such operating subsidiaries share customers and a particular customer may receive coal from any one of such operating subsidiaries.

F-28 

OXFORD RESOURCE PARTNERS, LP AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

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

NOTE 22: SUPPLEMENTAL QUARTERLY FINANCIAL INFORMATION - (Unaudited)

A summary of our unaudited consolidated quarterly operating results in 2013 and 2012 is as follows:

	2013
	March 31			June 30			September 30			December 31			Total
Total revenues	$	88,726		$	88,125		$	87,586		$	82,330		$	346,767
Net (loss) income from operations		(3,356	)		2,434			(1,036	)		(3,972	)		(5,930	)
Net loss attributable to Oxford Resource
Partners, LP unitholders		(6,547	)		(4,510	)		(5,599	)		(8,269	)		(24,925	)
Net loss allocated to general partner		(131	)		(89	)		(112	)		(165	)		(497	)
Net loss allocated to limited partners		(6,416	)		(4,421	)		(5,487	)		(8,104	)		(24,428	)
Loss per limited partner unit:
Basic	$	(0.31	)	$	(0.21	)	$	(0.22	)	$	(0.33	)	$	(1.07	)
Diluted	$	(0.31	)	$	(0.21	)	$	(0.22	)	$	(0.33	)	$	(1.07	)
Distributions paid per unit:
Limited partners:
Common	$	-		$	-		$	-		$	-		$	-
Subordinated	$	-		$	-		$	-		$	-		$	-
General partner	$	-		$	-		$	-		$	-		$	-

	2012
	March 31			June 30			September 30			December 31			Total
Total revenues	$	97,867		$	91,948		$	97,214		$	86,498		$	373,527
Net (loss) income from operations		(12,968	)		1,338			(29	)		(2,904	)		(14,563	)
Net loss attributable to Oxford Resource
Partners, LP unitholders		(15,776	)		(1,455	)		(3,314	)		(6,263	)		(26,808	)
Net loss allocated to general partner		(315	)		(29	)		(66	)		(125	)		(535	)
Net loss allocated to limited partners		(15,461	)		(1,426	)		(3,248	)		(6,138	)		(26,273	)
Loss per limited partner unit:
Basic	$	(0.75	)	$	(0.07	)	$	(0.16	)	$	(0.29	)	$	(1.27	)
Diluted	$	(0.75	)	$	(0.07	)	$	(0.16	)	$	(0.29	)	$	(1.27	)
Distributions paid per unit:
Limited partners:
Common	$	0.4375		$	0.4375		$	0.4375		$	0.2000		$	1.5125
Subordinated	$	0.4375		$	0.1000		$	0.1000		$	-		$	0.6375
General partner	$	0.4375		$	0.2688		$	0.2688		$	0.1000		$	1.0750

F-29

SIGNATURES

Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned thereunto duly authorized.

Date: March 4, 2014

OXFORD RESOURCE PARTNERS, LP
By:	OXFORD RESOURCES GP, LLC, its general partner
By:	/s/ CHARLES C. UNGUREAN
	Charles C. Ungurean
	President and Chief Executive Officer
	(Principal Executive Officer)
By:	/s/ BRADLEY W. HARRIS
	Bradley W. Harris
	Senior Vice President, Chief Financial Officer and Treasurer
	(Principal Financial Officer)

       

Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below by the following persons in their indicated capacities, which are with the general partner of the registrant, on the dates indicated.

Signature	Title	Date
/s/ GEORGE E. MCCOWN	Chairman of the Board	March 4, 2014
George E. McCown
/s/ CHARLES C. UNGUREAN	Director, President and Chief	March 4, 2014
Charles C. Ungurean	Executive Officer (principal executive officer)
/s/ BRADLEY W. HARRIS	Senior Vice President, Chief Financial	March 4, 2014
Bradley W. Harris	Officer and Treasurer (principal financial officer)
/s/ DENISE M. MAKSIMOSKI	Senior Director, Accounting	March 4, 2014
Denise M. Maksimoski	(principal accounting officer)
/s/ BRIAN D. BARLOW	Director	March 4, 2014
Brian D. Barlow
/s/ MATTHEW P. CARBONE	Director	March 4, 2014
Matthew P. Carbone
/s/ PETER B. LILLY	Director	March 4, 2014
Peter B. Lilly
/s/ ROBERT J. MESSEY	Director	March 4, 2014
Robert J. Messey
/s/ GERALD A. TYWONIUK	Director	March 4, 2014
Gerald A. Tywoniuk

100

Index to Exhibits

Exhibit Number	Description
3.1	Certificate of Limited Partnership of Oxford Resource Partners, LP (incorporated by reference to Exhibit 3.1 to the Registration Statement on Form S-1 (Commission File No. 333-165662) filed on March 24, 2010)
3.2	Third Amended and Restated Agreement of Limited Partnership of Oxford Resource Partners, LP dated July 19, 2010 (incorporated by reference to Exhibit 3.1 to the Current Report on Form 8-K (Commission File No. 001-34815) filed on July 19, 2010)
3.2A	First Amendment to Third Amended and Restated Limited Partnership Agreement of Oxford Resource Partners, LP dated June 24, 2013 (incorporated by reference to Exhibit 3.1 to the Current Report on Form 8-K (Commission File No. 001-34815) filed on June 25, 2013)
3.3	Certificate of Formation of Oxford Resources GP, LLC (incorporated by reference to Exhibit 3.3 to Amendment No. 1 to the Registration Statement on Form S-1 (Commission File No. 333-165662) filed on April 21, 2010)
3.4	Third Amended and Restated Limited Liability Company Agreement of Oxford Resources GP, LLC dated January 1, 2012 (incorporated by reference to Exhibit 3.2 to the Current Report on Form 8-K (Commission File No. 001-34815) filed on January 4, 2011)
3.4A	First Amendment to Third Amended and Restated Limited Liability Company Agreement of Oxford Resources GP, LLC dated June 24, 2013 (incorporated by reference to Exhibit 3.2 to the Current Report on Form 8-K (Commission File No. 001-34815) filed on June 25, 2013)
10.2	Investors’ Rights Agreement, dated August 24, 2007, by and among Oxford Resource Partners, LP, Oxford Resources GP, LLC, AIM Oxford Holdings, LLC, C&T Coal, Inc., Charles C. Ungurean and Thomas T. Ungurean (incorporated by reference to Amendment No. 3 to the Registration Statement on Form S-1 (Commission File No. 333-165662) filed on June 9, 2010)
10.2A	Amendment to Investors’ Rights Agreement dated June 24, 2013 by and among Oxford Resource Partners, LP, Oxford Resources GP, LLC, AIM Oxford Holdings, LLC, C&T Coal, Inc., Charles C. Ungurean and Thomas T. Ungurean (incorporated by reference to Exhibit 10.2A to the Quarterly Report on Form 10-Q (Commission File No. 001-34815) for the quarter ended June 30, 2013 filed on August 6, 2013)
10.4D#	Employment Agreement between Oxford Resources GP, LLC and Gregory J. Honish, which Employment Agreement was effective on March 29, 2013 (incorporated by reference to Exhibit 10.4D to the Annual Report on Form 10-K (Commission File No. 001-34815) for the year ended December 31, 2012 filed on April 1, 2013)
10.4E*#	Amendment to Employment Agreement between Oxford Resources GP, LLC and Gregory J. Honish, which Amendment was effective on March 3, 2014
10.5D#	Employment Agreement between Oxford Resources GP, LLC and Daniel M. Maher, which Employment Agreement was effective on March 29, 2013 (incorporated by reference to Exhibit 10.5D to the Annual Report on Form 10-K (Commission File No. 001-34815) for the year ended December 31, 2012 filed on April 1, 2013)
10.5E*#	Amendment to Employment Agreement between Oxford Resources GP, LLC and Daniel M. Maher, which Amendment was effective on March 3, 2014
10.6D#	Employment Agreement between Oxford Resources GP, LLC and Charles C. Ungurean, which Employment Agreement was effective on June 24, 2013 (incorporated by reference to Exhibit 10.6D to the Quarterly Report on Form 10-Q (Commission File No. 001-34815) for the quarter ended June 30, 2013 filed on August 6, 2013)

101

Exhibit Number	Description
10.9#	Employee Unitholder Agreement among Oxford Resource Partners, LP, Oxford Resources GP, LLC and Gregory J. Honish (incorporated by reference to Amendment No. 1 to the Registration Statement on Form S-1 (Commission File No. 333-165662) filed on April 21, 2010)
10.10#	Oxford Resource Partners, LP Amended and Restated Long-Term Incentive Plan dated July 19, 2010 (incorporated by reference to Exhibit 10.3 to the Current Report on Form 8-K (Commission File No. 001-34815) filed on July 19, 2010)
10.10A#	First Amendment to Oxford Resource Partners, LP Amended and Restated Long-Term Incentive Plan effective December 31, 2013 (incorporated by reference to Annex A to the Information Statement on Schedule 14C (Commission File No. 001-34815) filed on February 4, 2014)
10.11A#	Form of Long-Term Incentive Plan Award Agreement for Grant of Phantom Units for general use (incorporated by reference to Exhibit 10.11A to the Annual Report on Form 10-K (Commission File No. 001-34815) for the year ended December 31, 2011 filed on March 14, 2012)
10.11B#	Form of Long-Term Incentive Plan Award Agreement for Grant of Phantom Units for use with Charles C. Ungurean, Bradley W. Harris, Gregory J. Honish and Daniel M. Maher (incorporated by reference to Exhibit 10.11B to the Annual Report on Form 10-K (Commission File No. 001-34815) for the year ended December 31, 2011 filed on March 14, 2012)
10.12#	Non-Employee Director Compensation Plan adopted on June 28, 2011 and effective on January 1, 2011 (incorporated by reference to Exhibit 10.12 to the Annual Report on Form 10-K (Commission File No. 001-34815) for the year ended December 31, 2011 filed on March 14, 2012)
10.12A#	Non-Employee Director Compensation Plan adopted on February 28, 2013 and effective on January 1, 2013 (incorporated by reference to Exhibit 10.12A to the Annual Report on Form 10-K (Commission File No. 001-34815) for the year ended December 31, 2012 filed on April 1, 2013)
10.13#	Form of Non-Employee Director Compensation Plan Award Agreement for Grant of Unrestricted Units (incorporated by reference to Exhibit 10.13 to the Annual Report on Form 10-K (Commission File No. 001-34815) for the year ended December 31, 2011 filed on March 14, 2012)
10.14#	Director Unitholder Agreement, dated December 1, 2009, by and among Oxford Resource Partners, LP, Oxford Resources GP, LLC and Gerald A. Tywoniuk (incorporated by reference to Amendment No. 1 to the Registration Statement on Form S-1 (Commission File No. 333-165662) filed on April 21, 2010)
10.15	Acquisition Agreement, dated August 14, 2009, by and among Oxford Mining Company, LLC, Phoenix Coal Inc., Phoenix Coal Corporation and Phoenix Newco, LLC (incorporated by reference to Amendment No. 1 to the Registration Statement on Form S-1 (Commission File No. 333-165662) filed on April 21, 2010)
10.16A	Coal Purchase and Sale Agreement No. 10-62-04-900, dated May 21, 2004, by and between Oxford Mining Company, Inc. and American Electric Power Service Corporation, agent for Columbus Southern Power Company (incorporated by reference to Amendment No. 4 to the Registration Statement on Form S-1 (Commission File No. 333-165662) filed on June 25, 2010)
10.16B	Amendment No. 2004-1 to Coal Purchase and Sale Agreement, dated October 25, 2004 (incorporated by reference to Amendment No. 1 to the Registration Statement on Form S-1 (Commission File No. 333-165662) filed on April 21, 2010)

102

Exhibit Number	Description
10.16C	Amendment No. 2005-1 to Coal Purchase and Sale Agreement, dated April 8, 2005 (incorporated by reference to Amendment No. 4 to the Registration Statement on Form S-1 (Commission File No. 333-165662) filed on June 25, 2010)
10.16D	Amendment No. 2006-3 to Coal Purchase and Sale Agreement, dated December 5, 2006 (incorporated by reference to Amendment No. 4 to the Registration Statement on Form S-1 (Commission File No. 333-165662) filed on June 25, 2010)
10.16E	Amendment No. 2008-6 to Coal Purchase and Sale Agreement, dated December 29, 2008 (incorporated by reference to Amendment No. 4 to the Registration Statement on Form S-1 (Commission File No. 333-165662) filed on June 25, 2010)
10.16F	Amendment No. 2009-1 to Coal Purchase and Sale Agreement, dated May 21, 2009 (incorporated by reference to Amendment No. 4 to the Registration Statement on Form S-1 (Commission File No. 333-165662) filed on June 25, 2010)
10.16G	Amendment No. 2009-3 to Coal Purchase and Sale Agreement, dated December 15, 2009 (incorporated by reference to Amendment No. 4 to the Registration Statement on Form S-1 (Commission File No. 333-165662) filed on June 25, 2010)
10.16H	Amendment No. 2010-1 to Coal Purchase and Sale Agreement, dated January 11, 2010 (incorporated by reference to Amendment No. 4 to the Registration Statement on Form S-1 (Commission File No. 333-165662) filed on June 25, 2010)
10.16I†	Amendment No. 2010-2 to Coal Purchase and Sale Agreement, dated February 4, 2010 (incorporated by reference to Amendment No. 1 to the Registration Statement on Form S-1 (Commission File No. 333-165662) filed on April 21, 2010)
10.16J	Amendment No. 2010-3 to Coal Purchase and Sale Agreement, dated April 16, 2010 (incorporated by reference to Amendment No. 3 to the Registration Statement on Form S-1 (Commission File No. 333-165662) filed on June 9, 2010)
10.16K†	Amendment No. 2011-5 to Coal Purchase and Sale Agreement, dated October 26, 2011 (incorporated by reference to Exhibit 10.16K to the Annual Report on Form 10-K (Commission File No. 001-34815) for the year ended December 31, 2011 filed on March 14, 2012)
10.16L†	Amendment No. 2012-1 to Coal Purchase and Sale Agreement, dated March 21, 2012 (incorporated by reference to Exhibit 10.16L to the Quarterly Report on Form 10-Q (Commission File No. 001-34815) for the quarter ended March 31, 2012 filed on May 9, 2012)
10.16M†	Amendment No. 2012-2 to Coal Purchase and Sale Agreement, dated July 30, 2012 (incorporated by reference to Exhibit 10.16M to the Quarterly Report on Form 10-Q (Commission File No. 001-34815) for the quarter ended September 30, 2012 filed on November 7, 2012)
10.16N†	Amendment No. 2013-2 to Coal Purchase and Sale Agreement, dated February 6, 2013 (incorporated by reference to Exhibit 10.16N to the Annual Report on Form 10-K (Commission File No. 001-34815) for the year ended December 31, 2012 filed on April 1, 2013)
10.16O†	Amendment No. 2013-5 to Coal Purchase and Sale Agreement, dated June 26, 2013 (incorporated by reference to Exhibit 10.16O to the Quarterly Report on Form 10-Q (Commission File No. 001-34815) for the quarter ended June 30, 2013 filed on August 6, 2013)
10.16P*	Amendment No. 2014-1 to Coal Purchase and Sale Agreement, dated January 6, 2014
10.16Q*†	Amendment No. 2014-2 to Coal Purchase and Sale Agreement, dated February 27, 2014
10.17	Non-Compete Agreement by and among Oxford Resource Partners, LP, C&T Coal, Inc., Charles C. Ungurean, Thomas T. Ungurean and Oxford Resources GP, LLC (incorporated by reference to Amendment No. 3 to the Registration Statement on Form S-1 (Commission File No. 333-165662) filed on June 9, 2010)

103

Exhibit Number	Description
10.18	Administrative and Operational Services Agreement, dated August 24, 2007, by and among Oxford Resource Partners, LP, Oxford Mining Company, LLC and Oxford Resources GP, LLC (incorporated by reference to Amendment No. 1 to the Registration Statement on Form S-1 (Commission File No. 333-165662) filed on April 21, 2010)
10.19	Employment Agreement between Oxford Resources GP, LLC and Bradley W. Harris (incorporated by reference to Exhibit 10.19 to the Quarterly Report on Form 10-Q (Commission File No. 001-34815) for the quarter ended September 30, 2012 filed on November 7, 2012)
10.19A*#	Amendment to Employment Agreement between Oxford Resources GP, LLC and Bradley W. Harris dated as of March 3, 2014
10.20B#	Employment Agreement between Oxford Resources GP, LLC and Michael B. Gardner, which Employment Agreement was effective on March 29, 2013 (incorporated by reference to Exhibit 10.20B to the Annual Report on Form 10-K (Commission File No. 001-34815) for the year ended December 31, 2012 filed on April 1, 2013)
10.20C*#	Amendment to Employment Agreement between Oxford Resources GP, LLC and Michael B. Gardner dated as of March 3, 2014
10.21#	Retention bonus letter agreement between Oxford Resources GP, LLC and Bradley W. Harris dated as of March 29, 2013 (incorporated by reference to Exhibit 10.21 to the Annual Report on Form 10-K (Commission File No. 001-34815) for the year ended December 31, 2012 filed on April 1, 2013)
10.22#	Retention bonus letter agreement between Oxford Resources GP, LLC and Daniel M. Maher dated as of March 29, 2013 (incorporated by reference to Exhibit 10.22 to the Annual Report on Form 10-K (Commission File No. 001-34815) for the year ended December 31, 2012 filed on April 1, 2013)
10.23#	Retention bonus letter agreement between Oxford Resources GP, LLC and Gregory J. Honish dated as of March 29, 2013 (incorporated by reference to Exhibit 10.23 to the Annual Report on Form 10-K (Commission File No. 001-34815) for the year ended December 31, 2012 filed on April 1, 2013)
10.24	Financing Agreement, dated as of June 24, 2013, by and among Oxford Mining Company, LLC, as borrower, Oxford Resource Partners, LP, as a guarantor, the other guarantors party thereto, the lenders party thereto, and Cerberus Business Finance, LLC, as collateral agent and administrative agent for such lenders (incorporated by reference to Exhibit 10.24 to the Quarterly Report on Form 10-Q (Commission File No. 001-34815) for the quarter ended June 30, 2013 filed on August 6, 2013)
10.25	Financing Agreement, dated as of June 24, 2013, by and among Oxford Mining Company, LLC, as borrower, Oxford Resource Partners, LP, as a guarantor, the other guarantors party thereto, the lenders party thereto, and Obsidian Agency Services, Inc., as collateral agent and administrative agent for such lenders (incorporated by reference to Exhibit 10.25 to the Quarterly Report on Form 10-Q (Commission File No. 001-34815) for the quarter ended June 30, 2013 filed on August 6, 2013)
10.26	Intercreditor Agreement dated June 24, 2013 (incorporated by reference to Exhibit 10.26 to the Quarterly Report on Form 10-Q (Commission File No. 001-34815) for the quarter ended June 30, 2013 filed on August 6, 2013)
10.27	Warrant Issuance Agreement dated June 24, 2013 (incorporated by reference to Exhibit 10.27 to the Quarterly Report on Form 10-Q (Commission File No. 001-34815) for the quarter ended June 30, 2013 filed on August 6, 2013)

104

Exhibit Number	Description
10.28	Form of Warrant (to purchase common units of Oxford Resource Partners, LP) issued pursuant to the Warrant Issuance Agreement dated June 24, 2013 (incorporated by reference to Exhibit 10.28 to the Quarterly Report on Form 10-Q (Commission File No. 001-34815) for the quarter ended June 30, 2013 filed on August 6, 2013)
10.29	Form of Warrant (to purchase subordinated units of Oxford Resource Partners, LP) issued pursuant to the Warrant Issuance Agreement dated June 24, 2013 (incorporated by reference to Exhibit 10.29 to the Quarterly Report on Form 10-Q (Commission File No. 001-34815) for the quarter ended June 30, 2013 filed on August 6, 2013)
10.30	Form of Warrant (to purchase Class B Units of Oxford Resources GP, LLC) issued pursuant to the Warrant Issuance Agreement dated June 24, 2013 (incorporated by reference to Exhibit 10.30 to the Quarterly Report on Form 10-Q (Commission File No. 001-34815) for the quarter ended June 30, 2013 filed on August 6, 2013)
10.31	Investors’ Rights Agreement, dated as of June 24, 2013, by and among Oxford Resource Partners, LP, Oxford Resources GP, LLC, AIM Oxford Holdings, LLC, and the lenders party to the Financing Agreement, dated as of June 24, 2013, by and among Oxford Mining Company, LLC, as borrower, Oxford Resource Partners, LP, as a guarantor, the other guarantors party thereto, such lenders, and Obsidian Agency Services, Inc., as collateral agent and administrative agent for such lenders (incorporated by reference to Exhibit 10.31 to the Quarterly Report on Form 10-Q (Commission File No. 001-34815) for the quarter ended June 30, 2013 filed on August 6, 2013)
21.1*	List of Subsidiaries of Oxford Resource Partners, LP
23.1*	Consent of Grant Thornton LLP
23.2*	Consent of John T. Boyd Company
31.1*	Certification of Charles C. Ungurean, President and Chief Executive Officer of Oxford Resources GP, LLC, the general partner of Oxford Resource Partners, LP, for the December 31, 2013 Annual Report on Form 10-K, pursuant to Section 302 of the Sarbanes-Oxley Act of 2002
31.2*	Certification of Bradley W. Harris, Senior Vice President, Chief Financial Officer and Treasurer of Oxford Resources GP, LLC, the general partner of Oxford Resource Partners, LP, for the December 31, 2013 Annual Report on Form 10-K, pursuant to Section 302 of the Sarbanes-Oxley Act of 2002
32.1*	Certification of Charles C. Ungurean, President and Chief Executive Officer of Oxford Resources GP, LLC, the general partner of Oxford Resource Partners, LP, for the December 31, 2013 Annual Report on Form 10-K, pursuant to Section 906 of the Sarbanes-Oxley Act of 2002
32.2*	Certification of Bradley W. Harris, Senior Vice President, Chief Financial Officer and Treasurer of Oxford Resources GP, LLC, the general partner of Oxford Resource Partners, LP, for the December 31, 2013 Annual Report on Form 10-K, pursuant to Section 906 of the Sarbanes-Oxley Act of 2002

105

Exhibit Number	Description
95*	Mine Safety Disclosure
101*	Interactive data files pursuant to Rule 405 of Regulation S-T: (i) our Consolidated Balance Sheets as of December 31, 2013 and December 31, 2012; (ii) our Consolidated Statements of Operations for the years ended December 31, 2013, December 31, 2012 and December 31, 2011; (iii) our Consolidated Statements of Cash Flows for the years ended December 31, 2013, December 31, 2012 and December 31, 2011; (iv) our Consolidated Statements of Partners’ Capital for the years ended December 31, 2013, December 31, 2012 and December 31, 2011; and (v) the notes to our Consolidated Financial Statements (this information is furnished and not filed or part of a registration statement or prospectus for purposes of Sections 11 and 12 of the Securities Act of 1933, as amended, and Section 18 of the Securities Exchange Act of 1934, as amended)
*	Filed herewith (or furnished in the case of Exhibits 32.1, 32.2 and 101).
#	Compensatory plan or arrangement.
†	Certain portions have been omitted pursuant to a confidential treatment request. Omitted information has been filed separately with the Securities and Exchange Commission.

106

EX-10

EXHIBIT 10.4E

First amendment
to
Employment agreement

This FIRST AMENDMENT TO EMPLOYMENT AGREEMENT (this “Amendment”), effective as of March 3, 2014, is by and between Oxford Resources GP, LLC, a Delaware limited liability company (“Company”), and Gregory J. Honish (“Executive”).

recitals:

A.     According to the terms of that certain Employment Agreement (the “Employment Agreement”), dated March 29, 2013, by and between Company and Executive, Executive is employed in an executive position with Company.

B.     Both Company and Executive desire to amend the Employment Agreement to extend the term thereof by one (1) year so that the term will run until December 31, 2015;

C.     Accordingly, Company and Executive are entering into this Amendment for such purpose.

agreement:

In consideration of the premises and the mutual covenants and agreements set forth below, and for other good and valuable consideration not specified herein, the receipt and sufficiency of which are hereby acknowledged, the parties agree that Paragraph 2.1 (Term) of the Employment Agreement shall be and hereby is amended by replacing the date “December 31, 2014” where it appears therein with the date “December 31, 2015.”

IN WITNESS WHEREOF, the parties have set their hands hereto as of the date first above written.

Oxford Resources GP, LLC
By:	/s/ Charles C. Ungurean	/s/ Gregory J. Honish
Name: Title:	Charles C. Ungurean President and Chief Executive Officer	Name: Gregory J. Honish

EX-10

EXHIBIT 10.5E

First amendment
to
Employment agreement

This FIRST AMENDMENT TO EMPLOYMENT AGREEMENT (this “Amendment”), effective as of March 3, 2014, is by and between Oxford Resources GP, LLC, a Delaware limited liability company (“Company”), and Daniel M. Maher (“Executive”).

recitals:

A.     According to the terms of that certain Employment Agreement (the “Employment Agreement”), dated March 29, 2013, by and between Company and Executive, Executive is employed in an executive position with Company.

B.     Both Company and Executive desire to amend the Employment Agreement to extend the term thereof by one (1) year so that the term will run until December 31, 2015;

C.     Accordingly, Company and Executive are entering into this Amendment for such purpose.

agreement:

In consideration of the premises and the mutual covenants and agreements set forth below, and for other good and valuable consideration not specified herein, the receipt and sufficiency of which are hereby acknowledged, the parties agree that Paragraph 2.1 (Term) of the Employment Agreement shall be and hereby is amended by replacing the date “December 31, 2014” where it appears therein with the date “December 31, 2015.”

IN WITNESS WHEREOF, the parties have set their hands hereto as of the date first above written.

Oxford Resources GP, LLC
By:	/s/ Charles C. Ungurean	/s/ Daniel M. Maher
Name: Title:	Charles C. Ungurean President and Chief Executive Officer	Name: Daniel M. Maher

EX-10

EXHIBIT 10.16P

155 West Nationwide Boulevard

Columbus, OH 43215

January 6, 2014

Oxford Mining Company, LLC

Attn: Ms. Angela Ashcraft

544 Chestnut Street

Coshocton, OH 43812

Re: Coal Purchase and Sale Agreement No. 10-62-04-900, dated May 21, 2004, as amended, between AEP Generation Resources Inc. (successor in interest to Ohio Power Company(f/k/a Columbus Southern Power Company)) (“Buyer”) and Oxford Mining Company, LLC (formerly Oxford Mining Company, Inc.) (“Seller”)

SUBJECT: AMENDMENT 2014-1

Reference is made to the above-referenced Coal Purchase and Sale Agreement, as amended (the “Agreement”), under which Seller is supplying coal to Buyer.

Effective January 1, 2014, Buyer and Seller agree to amend the Agreement as follows:

A. In ARTICLE II, Obligations and Deliveries, Table 2.1.1 (excluding the notes immediately below and relating to Table 2.1.1) shall be deleted in its entirety and replaced with the following in lieu thereof:

Table 2.1.1

Contract Year(s)	Annual Contract Quantity	Spec A Coal Tons	Spec B Coal Tons	Option No. 1 Tons	Option No. 2 Tons	Additional Spec B Coal Tons
2009	1,750,000	500,000	(3)	---	---	---
2010 – 2011	1,700,000	500,000	(3)	---	---	---
2012 – Q 1 and Q2(1)	501,049	0	501,049	0 to 50,000/qtr(4)	50,001 – 100,000/qtr (5)	---
2012 – Q 3 and Q4(1)	809,147(6)	0	809,147(6)	0 to 50,000/qtr(4)	50,001 – 100,000/qtr (5)	---
2013	1,630,000(8)	0	1,630,000(8)	0 to 50,000/qtr(4)	50,001 – 100,000/qtr (5)	75,000(7)
2014	1,650,000	0	1,650,000	0 to 50,000/qtr(4)	50,001 – 100,000/qtr (5)	---
2015	1,700,000	0	1,700,000	0 to 50,000/qtr(4)	50,001 – 100,000/qtr (5)	---
2016 – 2018(2)	1,700,000	0	1,700,000	0 to 50,000/qtr(4)	50,001 – 100,000/qtr (5)	---

Oxford Mining Company, LLC

Coal Purchase and Sales Agreement 10-62-04-900

Amendment 2014-1

January 6, 2014

Page 2

The notes immediately below and relating to Table 2.1.1 shall remain the same for the above replacement Table 2.1.1.

Except as amended herein, all other provisions of the Agreement shall remain in full force and effect. If you are in agreement with the foregoing, kindly indicate your acceptance thereof and agreement thereto by signing in the space below and returning one original to the attention of Buyer’s Fuel Contract Administration at the address provided in the Agreement.

	Accepted and agreed: OXFORD MINING COMPANY, LLC
James D. Henry Vice President – Fuel Procurement AEP Generation Resources Inc.	/s/ Charles C. Ungurean
	Signature
	Charles C. Ungurean
	Name
	President and Chief Executive Officer
	Title

EX-10

Exhibit 10.16Q

[*] Certain information in this document has been omitted and filed separately with the Securities and Exchange Commission. Confidential treatment has been requested with respect to the omitted portions.

February 27, 2014

Oxford Mining Company, LLC

Attn: Ms. Angela Ashcraft

544 Chestnut Street

Coshocton, OH 43812

Re: Coal Purchase and Sale Agreement No. 10-62-04-900, dated May 21, 2004, as amended, between AEP Generation Resources Inc. (successor in interest to Ohio Power Company(f/k/a Columbus Southern Power Company)) (“Buyer”) and Oxford Mining Company, LLC (formerly Oxford Mining Company, Inc.) (“Seller”)

SUBJECT: AMENDMENT 2014-2

Reference is made to the above-referenced Coal Purchase and Sale Agreement, as amended (the “Agreement”), under which Seller is supplying coal to Buyer.

Effective January 1, 2014, Buyer and Seller agree to amend the Agreement as follows:

A. In ARTICLE V, Contract Price, Table 5.1 and the notes immediately below and relating thereto shall be deleted in their entirety and replaced with the following in lieu thereof

Table 5.1

Contract Year	Price Per Ton- Specification B Coal	Price Per Ton- Additional Tons
FOB Plant:
[*](1)	$[*]	---
[*](1)	$[*]	---
[*](1)(2)	$[*]	---
[*]	$[*]	$[*](4)
[*]	$[*]	---
[*]	[*]	---
[*](3)	[*]	---

⁽¹⁾ For purposes of the provisions related to ARTICLE V, Contract Price, the Q1 and Q2 of 2012 period is treated collectively as a Contract Year and the Q3 and Q4 of 2012 period is treated collectively as a Contract Year.

⁽²⁾ The Contract Price listed above for 2012 - Q4 is the reconciliation price based upon the formula calculation set forth below in this Article V a).

⁽³⁾ If the Option Term Extension is elected by Buyer.

⁽⁴⁾ The price shown is the price per ton for the additional 75,000 tons of Specification B Coal being shipped by Seller to Buyer in the months of February through April 2013 in accordance with Table 2.1.1 and Note ⁽⁷⁾ thereto.

⁽⁵⁾For the Specification B Coal being provided by Seller to Buyer in accordance with Note ⁽⁸⁾ to Table 2.1.1, the price per ton will be increased to $[*]. Quality adjustments to the price will not apply to such Specification B Coal being provided by Seller to Buyer in accordance with Note ⁽⁸⁾ to Table 2.1.1.

Oxford Mining Company, LLC

Coal Purchase and Sales Agreement 10-62-04-900

Amendment 2014-2

February 27, 2014

Except as amended herein, all other provisions of the Agreement shall remain in full force and effect. If you are in agreement with the foregoing, kindly indicate your acceptance thereof and agreement thereto by signing in the space below and returning one original to the attention of Buyer’s Fuel Contract Administration at the address provided in the Agreement.

	Accepted and agreed:
/s/James D. Henry	OXFORD MINING COMPANY, LLC
James D. Henry
Vice President – Fuel Procurement
AEP Generation Resources Inc.	/s/ Charles C. Ungurean_____________
	Signature
	/s/ Charles C. Ungurean
	Name
	President and Chief Executive Officer
	Title

[*] Certain information in this document has been omitted and filed separately with the Securities and Exchange Commission. Confidential treatment has been requested with respect to the omitted portions.

EX-10

EXHIBIT 10.19A

First amendment
to
Employment agreement

This FIRST AMENDMENT TO EMPLOYMENT AGREEMENT (this “Amendment”), effective as of March 3, 2014, is by and between Oxford Resources GP, LLC, a Delaware limited liability company (“Company”), and Bradley W. Harris (“Executive”).

recitals:

A.     According to the terms of that certain Employment Agreement (the “Employment Agreement”), dated March 29, 2013, by and between Company and Executive, Executive is employed in an executive position with Company.

B.     Both Company and Executive desire to amend the Employment Agreement to extend the term thereof by one (1) year so that the term will run until December 31, 2015;

C.     Accordingly, Company and Executive are entering into this Amendment for such purpose.

agreement:

In consideration of the premises and the mutual covenants and agreements set forth below, and for other good and valuable consideration not specified herein, the receipt and sufficiency of which are hereby acknowledged, the parties agree that Paragraph 2.1 (Term) of the Employment Agreement shall be and hereby is amended by replacing the date “December 31, 2014” where it appears therein with the date “December 31, 2015.”

IN WITNESS WHEREOF, the parties have set their hands hereto as of the date first above written.

Oxford Resources GP, LLC
By:	/s/ Charles C. Ungurean	/s/ Bradley W. Harris
Name: Title:	Charles C. Ungurean President and Chief Executive Officer	Name: Bradley W. Harris

EX-10

EXHIBIT 10.20c

First amendment

to

Employment agreement

This FIRST AMENDMENT TO EMPLOYMENT AGREEMENT (this “Amendment”), effective as of March 3, 2014, is by and between Oxford Resources GP, LLC, a Delaware limited liability company (“Company”), and Michael B. Gardner (“Executive”).

recitals:

A.     According to the terms of that certain Employment Agreement (the “Employment Agreement”), dated March 29, 2013, by and between Company and Executive, Executive is employed in an executive position with Company.

B.     Both Company and Executive desire to amend the Employment Agreement to extend the term thereof by one (1) year so that the term will run until December 31, 2015;

C.     Accordingly, Company and Executive are entering into this Amendment for such purpose.

agreement:

In consideration of the premises and the mutual covenants and agreements set forth below, and for other good and valuable consideration not specified herein, the receipt and sufficiency of which are hereby acknowledged, the parties agree that Paragraph 2.1 (Term) of the Employment Agreement shall be and hereby is amended by replacing the date “December 31, 2014” where it appears therein with the date “December 31, 2015.”

IN WITNESS WHEREOF, the parties have set their hands hereto as of the date first above written.

Oxford Resources GP, LLC
By:	/s/ Charles C. Ungurean	/s/ Michael B. Gardner
Name: Title:	Charles C. Ungurean President and Chief Executive Officer	Name: Michael B. Gardner

EX-21

Exhibit 21.1

LIST OF SUBSIDIARIES OF OXFORD RESOURCE PARTNERS, LP

First Tier Subsidiary:

Oxford Mining Company, LLC, an Ohio limited liability company ("OMC")

Second Tier Subsidiary:

Oxford Mining Company — Kentucky, LLC, a Kentucky limited liability company (OMC holds a 100% membership interest)

Daron Coal Company, LLC, an Ohio limited liability company (OMC holds a 100% membership interest)

Oxford Conesville, LLC, an Ohio limited liability company (OMC holds a 100% membership interest)

EX-23

EXHIBIT 23.1

CONSENT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

We have issued our report dated March 4, 2014, with respect to the consolidated financial statements included in the Annual Report on Form 10-K for the year ended December 31, 2013 of Oxford Resource Partners, LP, which is incorporated by reference in the Registration Statements of Oxford Resource Partners, LP on Form S-8 (File No. 333-168454, effective August 2, 2010), Form S-3 (File No. 333-178425, effective December 9, 2011), and Form S-8 (File No. 333-194259, effective March 3, 2014). We consent to the incorporation by reference in the Registration Statements of the aforementioned report, and to the use of our name as it appears under the caption “Experts”.

/s/GRANT THORNTON LLP

Cleveland, Ohio

March 4, 2014

EX-23

EXHIBIT 23.2

CONSENT OF JOHN T. BOYD COMPANY

As mining and geological consultants, we hereby consent to the use by Oxford Resource Partners, LP (the "Partnership") in connection with its Annual Report on Form 10-K for the year ended December 31, 2013 (the "Form 10-K"), and any amendments thereto, and to the incorporation by reference in the Partnership's Registration Statements on Form S-8 (No. 333-168454), Form S-3 (No. 333-178425) and Form S-8 (File No. 333-194259). of information contained in our report dated January 29, 2014, addressed to the Partnership, relating to estimates of coal reserves of the Partnership located in Northern Appalachia and the Illinois Basin including setting forth the estimates of the Partnership's coal reserves in the Form 10-K. We also consent to the reference to John T. Boyd Company in those filings and any amendments thereto.

John T. Boyd Company

By:	/s/ Ronald L. Lewis
	Ronald L. Lewis
	Managing Director and COO

Date: March 4, 2014

EX-31

EXHIBIT 31.1

CERTIFICATION

I, Charles C. Ungurean, certify that:

1.	I have reviewed this Annual Report on Form 10-K of Oxford Resource Partners, LP;
2.	Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;
3.	Based on my knowledge, the financial statements, and other financial information included in this report fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;
4.	The registrant's other certifying officer and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have:
	a.	Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;
	b.	Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles;
	c.	Evaluated the effectiveness of the registrant's disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and
	d.	Disclosed in this report any change in the registrant's internal control over financial reporting that occurred during the registrant's most recent fiscal quarter (the registrant's fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant's internal control over financial reporting; and
5.	The registrant’s other certifying officer and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant’s auditors and the audit committee of the registrant’s board of directors (or persons performing the equivalent functions):
	a.	All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant’s ability to record, process, summarize and report financial information; and
	b.	Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal control over financial reporting.

Date: March 4, 2014	/s/ CHARLES C. UNGUREAN
	Charles. C. Ungurean
	President and Chief Executive Officer of Oxford Resources GP, LLC (the general partner of Oxford Resource Partners, LP)  (Principal Executive Officer)

EX-31

EXHIBIT 31.2 

CERTIFICATION

I, Bradley W. Harris, certify that:

1.	I have reviewed this Annual Report on Form 10-K of Oxford Resource Partners, LP;
2.	Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;
3.	Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;
4.	The registrant's other certifying officer and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have:
	a.	Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;
	b.	Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles;
	c.	Evaluated the effectiveness of the registrant's disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and
	d.	Disclosed in this report any change in the registrant's internal control over financial reporting that occurred during the registrant's most recent fiscal quarter (the registrant's fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant's internal control over financial reporting; and
5.	The registrant’s other certifying officer and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant’s auditors and the audit committee of the registrant’s board of directors (or persons performing the equivalent functions):
	a.	All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant’s ability to record, process, summarize and report financial information; and
	b.	Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal control over financial reporting.

Date: March 4, 2014	/s/ BRADLEY W. HARRIS
	Bradley W. Harris
	Senior Vice President, Chief Financial Officer and Treasurer of Oxford Resources GP, LLC (the general partner of Oxford Resource Partners, LP) (Principal Financial Officer)

EX-32

EXHIBIT 32.1 

CERTIFICATION OF PRINCIPAL EXECUTIVE OFFICER
PURSUANT TO 18 U.S.C. SECTION 1350

In connection with the Annual Report of Oxford Resource Partners, LP (the “Partnership”) on Form 10-K for the period ended December 31, 2013 as filed with the Securities and Exchange Commission on the date hereof (the “Report”), I, Charles C. Ungurean, President and Chief Executive Officer of Oxford Resources GP, LLC, the general partner of the Partnership, certify, pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002 (“Section 906”), that:

(1)	the Report fully complies with the requirements of Section 13(a) or 15(d), as applicable, of the Securities Exchange Act of 1934, as amended; and
(2)	the information contained in the Report fairly presents, in all material respects, the financial condition and results of operations of the Partnership.

Date: March 4, 2014 

By:	/s/ CHARLES C. UNGUREAN
	Charles C. Ungurean
	President and Chief Executive Officer of Oxford Resources GP, LLC (the general partner of Oxford Resource Partners, LP)

The foregoing certification is being furnished solely pursuant to 18 U.S.C. Section 1350 and is not being filed as part of the Report or as a separate document. A signed original of this written statement required by Section 906 has been provided to the Partnership and will be retained by the Partnership and furnished to the Securities and Exchange Commission or its staff upon request.

EX-32

EXHIBIT 32.2 

CERTIFICATION OF PRINCIPAL FINANCIAL OFFICER
PURSUANT TO 18 U.S.C. SECTION 1350

In connection with the Annual Report of Oxford Resource Partners, LP (the “Partnership”) on Form 10-K for the period ended December 31, 2013 as filed with the Securities and Exchange Commission on the date hereof (the “Report”), I, Bradley W. Harris, Senior Vice President, Chief Financial Officer and Treasurer of Oxford Resources GP, LLC, the general partner of the Partnership, certify, pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002 (“Section 906”), that:

(1)	the Report fully complies with the requirements of Section 13(a) or 15(d), as applicable, of the Securities Exchange Act of 1934, as amended; and
(2)	information contained in the Report fairly presents, in all material respects, the financial condition and results of operations of the Partnership.

Date: March 4, 2014

By:	/s/ BRADLEY W. HARRIS
	Bradley W. Harris
	Senior Vice President, Chief Financial Officer and Treasurer of Oxford Resources GP, LLC (the general partner of Oxford Resource Partners, LP)

The foregoing certification is being furnished solely pursuant to 18 U.S.C. Section 1350 and is not being filed as part of the Report or as a separate document. A signed original of this written statement required by Section 906 has been provided to the Partnership and will be retained by the Partnership and furnished to the Securities and Exchange Commission or its staff upon request.

EX-95

Exhibit 95

Mine Safety Disclosure

The information concerning mine safety violations or other regulatory matters required by Section 1503(a) of the Dodd-Frank Wall Street Reform and Consumer Protection Act and Section 104 of Regulation S-K, is included in this Exhibit 95.

For each coal mine for which we or a subsidiary is an operator within the meaning of Section 3 of the Mine Act during 2013, we include the following table that sets forth: (A) the total number of violations of mandatory health or safety standards that could significantly and substantially contribute to the cause and effect of a coal or other mine safety or health hazard under Section 104 of the Mine Act for which we received a citation from the MSHA; (B) the total number of failure to abate orders issued under Section 104(b) of the Mine Act; (C) the total number of citations and orders for unwarrantable failure to comply with mandatory health or safety standards under Section 104(d) of the Mine Act; (D) the total number of flagrant violations under Section 110(b)(2) of the Mine Act; (E) the total number of imminent danger orders issued under Section 107(a) of the Mine Act; (F) the total dollar value of the proposed MSHA assessments under the Mine Act ; and (G) the total number of mining-related fatalities.

In addition, no coal mine for which we or a subsidiary were the operator received written notice from MSHA of a pattern of violations, or the potential to have such a pattern, of mandatory health or safety standards that are of such nature as could have significantly and substantially contributed to the cause and effect of coal or other mine health or safety hazards under Section 104(e) of the Mine Act.

The total number of legal actions pending before the Federal Mine Safety and Review Commission (the “FMSR Commission”) as of December 31, 2013 was three (3). The aggregate number of legal actions during the period covered by this report instituted (either by MSHA or by us) was nine (9) and resolved (meaning final order entered and not appealed) was fifteen (15). Of the legal actions pending before the FMSR Commission as of December 31, 2013, the number of such legal actions that fall into each of the following categories was as follows: (a) contests of citations and orders: zero (0); (b) contests of proposed penalties: two (2); (c) complaints for compensation under Section 111 of the Mine Act: zero (0); (d) complaints of discharge, discrimination or interference under Section 105 of the Mine Act: one (1); (e) applications for temporary relief under Section 105(b)(2) of the Mine Act: zero (0); and (f) appeals of judges' decisions or orders to the FMSR Commission: zero (0).

Mine Safety Disclosure (continued) 

Oxford Complex	MSHA Mine ID		MSHA Mine Name	(A) Section 104 S&S Citations (#)		(B) Section 104(b) Orders (#)		(C) Section 104(d) Citations & Orders (#)		(D) Section 110(b)(2) Flagrant Violations (#)		(E) Section 107(a) Imminent Danger Orders (#)		(F) Total Value of Proposed MSHA Assessments(1) ($)			(G) Mining- Related Fatalities (#)
		1518134	Halls Creek		2		-		-		-		-		$	3,843		-
		1518912	Island Dock		-		-		-		-		-			-		-
Muhlenberg		1519365	Schoate Preparation Plant		2		-		-		-		-		$	162		-
		1519452	Star		-		-		-		-		-			-		-
		1519466	Rose France		-		-		-		-		-			-		-
		1519655	Geibel		-		-		-		-		-			-		-
		3300965	Rice #1		2		-		-		-		-		$	5,260		-
Belmont		3302937	Loading Dock		-		-		-		-		-		$	200		-
		3303758	Valley Mining, Inc./Auger #1		-		-		-		-		-		$	100		-
		3304413	Standing Stone Mine		-		-		-		-		-		$	100		-
Cadiz		3304414	Snyder Mine		3		-		-		-		-		$	2,549		-
		3304538	Dairy Jean		5		-		-		-		-		$	1,748		-
		4609067	Crosscreek Mine		-		-		-		-		-			-		-
Harrison		3304577	Harrison Resources, LLC/Sexton 2 Pit		-		-		-		-		-		$	700		-
New Lexington		3304336	Oxford Mining #3		2		-		-		-		-		$	2,050		-
		3304637	Athens		-		-		-		-		-			-		-
Noble		3303770	Rice #2		-		-		-		-		-			-		-
		3304624	Oxford Guernsey		1		-		-		-		-		$	262		-
Plainfield		3303288	Rice #7		1		-		-		-		-		$	100		-
		3303907	Conesville Plant		-		-		-		-		-		$	100		-
		3304180	Coshocton Strip		-		-		-		-		-			-		-
		3304213	Oxford Mining #2		1		-		-		-		-		$	362		-
		3303930	Lisbon Mine		-		-		-		-		-		$	100		-
Tuscarawas		3304179	Tuscarawas Strip		1		-		-		-		-		$	1,741		-
		3304181	Stark Strip		1		-		-		-		-		$	562		-
					21		0		0		0		0		$	19,939		0

⁽¹⁾ The total dollar value of proposed MSHA assessments is the amount issued during the current reporting period for all citations, orders or violations, not just those indicated herein, and do not necessarily relate to the citations, orders or violations issued by MSHA during the current reporting period or to the pending legal actions reported in Exhibit 95.

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Note 11 - Fair Value of Financial Instruments (Tables)

12 Months Ended

Dec. 31, 2013

Fair Value Disclosures [Abstract]

Schedule of Fair Value, Assets and Liabilities Measured on Recurring Basis [Table Text Block]

	Fair Value Measurements as of December 31, 2013
	Quoted Prices in Active Markets for Identical Liabilities		Significant Other Observable Inputs			Significant Unobservable Inputs
Description	(Level 1)		(Level 2)			(Level 3)
Warrants	$	-	$	(4,599	)	$	-

	Fair Value Measurements as of December 31, 2012
	Quoted Prices in Active Markets for Identical Liabilities		Significant Other Observable Inputs			Significant Unobservable Inputs
Description	(Level 1)		(Level 2)			(Level 3)
Interest rate swap agreement	$	-	$	(12	)	$	-

Fair Value, by Balance Sheet Grouping [Table Text Block]

	As of December 31, 2013				As of December 31, 2012
	Carrying Amount		Fair Value		Carrying Amount		Fair Value
Fixed rate debt	$	3,593	$	3,386	$	7,527	$	7,642
Variable rate debt		159,683		159,683		137,000		137,000

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Note 5 - Property, Plant and Equipment, Net (Details) - Property, Plant and Equipment, Net (USD $) In Thousands, unless otherwise specified	Dec. 31, 2013	Dec. 31, 2012
Property, plant and equipment, gross:
Land	$ 3,016	$ 2,947
Property, plant and equipment, gross	321,553	305,943
Furniture and fixtures	1,584	1,518
Machinery and equipment	202,663	195,321
Less: accumulated depreciation, depletion and amortization	(177,127)	(147,460)
Total property, plant and equipment, net	144,426	158,483
Coal Reserves [Member]
Property, plant and equipment, gross:
Property, plant and equipment, gross	49,574	53,376
Mine Development Costs [Member]
Property, plant and equipment, gross:
Property, plant and equipment, gross	58,077	46,176
Buildings and Tipple [Member]
Property, plant and equipment, gross:
Property, plant and equipment, gross	1,957	1,957
Vehicles [Member]
Property, plant and equipment, gross:
Property, plant and equipment, gross	4,522	4,488
Railroad Transportation Equipment [Member]
Property, plant and equipment, gross:
Property, plant and equipment, gross	$ 160	$ 160

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Note 2 - Summary of Significant Accounting Policies (Details) - Property Plant and Equipment Useful Lives	12 Months Ended
	Dec. 31, 2013
Buildings and Tipple [Member] | Minimum [Member]
Note 2 - Summary of Significant Accounting Policies (Details) - Property Plant and Equipment Useful Lives [Line Items]
Property, plant and equipment estimated useful lives	25 years
Buildings and Tipple [Member] | Maximum [Member]
Note 2 - Summary of Significant Accounting Policies (Details) - Property Plant and Equipment Useful Lives [Line Items]
Property, plant and equipment estimated useful lives	39 years
Machinery and Equipment [Member] | Minimum [Member]
Note 2 - Summary of Significant Accounting Policies (Details) - Property Plant and Equipment Useful Lives [Line Items]
Property, plant and equipment estimated useful lives	1 year
Machinery and Equipment [Member] | Maximum [Member]
Note 2 - Summary of Significant Accounting Policies (Details) - Property Plant and Equipment Useful Lives [Line Items]
Property, plant and equipment estimated useful lives	12 years
Automobiles [Member] | Minimum [Member]
Note 2 - Summary of Significant Accounting Policies (Details) - Property Plant and Equipment Useful Lives [Line Items]
Property, plant and equipment estimated useful lives	5 years
Automobiles [Member] | Maximum [Member]
Note 2 - Summary of Significant Accounting Policies (Details) - Property Plant and Equipment Useful Lives [Line Items]
Property, plant and equipment estimated useful lives	7 years
Furniture and Fixtures [Member] | Minimum [Member]
Note 2 - Summary of Significant Accounting Policies (Details) - Property Plant and Equipment Useful Lives [Line Items]
Property, plant and equipment estimated useful lives	3 years
Furniture and Fixtures [Member] | Maximum [Member]
Note 2 - Summary of Significant Accounting Policies (Details) - Property Plant and Equipment Useful Lives [Line Items]
Property, plant and equipment estimated useful lives	7 years
Railroad Transportation Equipment [Member]
Note 2 - Summary of Significant Accounting Policies (Details) - Property Plant and Equipment Useful Lives [Line Items]
Property, plant and equipment estimated useful lives	7 years

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Note 11 - Fair Value of Financial Instruments (Details) - Carrying Amounts and Fair Values of Financial Instruments, Fair Value Option Not Elected (USD $) In Thousands, unless otherwise specified	Dec. 31, 2013	Dec. 31, 2012
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Carrying Amount	$ 163,276	$ 144,527
Fixed Rate Debt [Member]
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Carrying Amount	3,593	7,527
Fair Value	3,386	7,642
Variable Rate Debt [Member]
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Carrying Amount	159,683	137,000
Fair Value	$ 159,683	$ 137,000

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Note 5 - Property, Plant and Equipment, Net (Details) - Depreciation, Depletion, and Amortization (USD $) In Thousands, unless otherwise specified	12 Months Ended
	Dec. 31, 2013		Dec. 31, 2012		Dec. 31, 2011
Depreciation, Depletion, and Amortization [Abstract]
Depreciation	$ 30,786		$ 34,276		$ 37,022
Depletion	4,513		4,869		5,697
Mine development amortization	12,528		11,783		8,913
Intangible asset amortization(1)	254	[1]	242	[1]	273	[1]
	$ 48,081		$ 51,170		$ 51,905

[1] See Note 7.

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Note 16 - Retirement Plan (Details) (USD $) In Millions, unless otherwise specified	12 Months Ended
	Dec. 31, 2012	Dec. 31, 2011
Compensation and Retirement Disclosure [Abstract]
Defined Contribution Plan Employer Contribution Percent	4.00%
Defined Contribution Plan, Employer Discretionary Contribution Amount	$ 1.9	$ 2.2

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Note 1 - Organization and Presentation (Details)	Dec. 31, 2013
Note 1 - Organization and Presentation (Details) [Line Items]
Noncontrolling Interest, Ownership Percentage by Noncontrolling Owners	49.00%
Chief Legal Officer [Member] | General Partner [Member]
Note 1 - Organization and Presentation (Details) [Line Items]
Percentage of Partner Interest	0.47%
Jeffrey M Gutman [Member] | General Partner [Member]
Note 1 - Organization and Presentation (Details) [Line Items]
Percentage of Partner Interest	0.23%
Harrison Resources [Member]
Note 1 - Organization and Presentation (Details) [Line Items]
Noncontrolling Interest, Ownership Percentage by Parent	51.00%
Noncontrolling Interest, Ownership Percentage by Noncontrolling Owners	49.00%
AIM Oxford Holdings [Member] | General Partner [Member]
Note 1 - Organization and Presentation (Details) [Line Items]
Percentage of Partner Interest	65.81%
AIM Oxford Holdings [Member] | Limited Partner [Member]
Note 1 - Organization and Presentation (Details) [Line Items]
Percentage of Partner Interest	35.33%
C & T Coal [Member] | General Partner [Member]
Note 1 - Organization and Presentation (Details) [Line Items]
Percentage of Partner Interest	33.49%
C & T Coal [Member] | Limited Partner [Member]
Note 1 - Organization and Presentation (Details) [Line Items]
Percentage of Partner Interest	17.98%
General Public and LTIP Participants [Member] | Limited Partner [Member]
Note 1 - Organization and Presentation (Details) [Line Items]
Percentage of Partner Interest	44.70%
General Partner [Member]
Note 1 - Organization and Presentation (Details) [Line Items]
Percentage of Partner Interest	1.99%

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Note 5 - Property, Plant and Equipment, Net (Tables)

12 Months Ended

Dec. 31, 2013

Property, Plant and Equipment [Abstract]

Property, Plant and Equipment, Net [Table Text Block]

	As of December 31,
	2013			2012
Property, plant and equipment, gross:
Land	$	3,016		$	2,947
Coal reserves		49,574			53,376
Mine development costs		58,077			46,176
Buildings and tipple		1,957			1,957
Machinery and equipment		202,663			195,321
Vehicles		4,522			4,488
Furniture and fixtures		1,584			1,518
Railroad sidings		160			160
Total property, plant and equipment, gross		321,553			305,943
Less: accumulated depreciation, depletion and amortization		(177,127	)		(147,460	)
Total property, plant and equipment, net	$	144,426		$	158,483

Schedule of Depreciation, Depletion, and Amortization [Table Text Block]

	For the Year Ended December 31,
	2013		2012		2011
Depreciation	$	30,786	$	34,276	$	37,022
Depletion		4,513		4,869		5,697
Mine development amortization		12,528		11,783		8,913
Intangible asset amortization(1)		254		242		273
	$	48,081	$	51,170	$	51,905

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Note 17 - Commitments and Contingencies (Details) (USD $)	12 Months Ended			12 Months Ended		12 Months Ended		1 Months Ended
	Dec. 31, 2012	Dec. 31, 2011	Dec. 31, 2013	Dec. 31, 2013 Previously [Member] Coal [Member] T	Dec. 31, 2013 Cash Collateralized Bonds [Member]	Dec. 31, 2013 Coal [Member] T	Dec. 31, 2012 General Partner [Member]	Feb. 28, 2013 Purchase Commitment [Member]	Dec. 31, 2013 Minimum [Member]	Dec. 31, 2013 Maximum [Member]
Note 17 - Commitments and Contingencies (Details) [Line Items]
Remaining Life of Long Term Contract									1 year	2 years
Supply Commitment, Amount of Product (in US Tons)						800,000
Long-term Purchase Commitment, Minimum Mass Required (in US Tons)				400,000
Gain (Loss) on Contract Termination								$ 2,100,000
Defined Contribution Plan, Employer Discretionary Contribution Amount	1,900,000	2,200,000					1,900,000
Surety Bonds Outstanding			37,000,000
Line of Credit Facility, Amount Outstanding					9,600,000
Road Bonds Outstanding			600,000
Performance Bonds Outstanding			$ 2,100,000

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Note 13 - Earnings (Losses) Per Unit (Details) (USD $) In Millions, unless otherwise specified	Dec. 31, 2013
Earnings Per Share [Abstract]
Unit Amount of Dividends in Arrears	$ 25.3

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Note 6 - Operating Leases (Details) - Future Lease Payments (USD $) In Thousands, unless otherwise specified	Dec. 31, 2013
Future Lease Payments [Abstract]
For the years ending December 31, 2014	$ 7,928
2015	5,947
2016	2,642
2017	651
2018	$ 2

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Note 14 - Noncontrolling Interest (Details) - Components of Noncontrolling Interest (USD $) In Thousands, unless otherwise specified	12 Months Ended
	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
Components of Noncontrolling Interest [Abstract]
Beginning balance	$ 3,744	$ 2,989
Net income	1,225	755	4,748
Ending balance	$ 4,969	$ 3,744	$ 2,989

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Note 18 - Concentration of Credit Risk and Major Customers (Details) - Amount of Sales to Each Customer (Sales Revenue, Net [Member], USD $)	12 Months Ended
	Dec. 31, 2013		Dec. 31, 2012		Dec. 31, 2011
American Electric Power [Member]
Revenue, Major Customer [Line Items]
Customer Revenue	$ 146,300		$ 128,800		$ 139,700
First Energy [Member]
Revenue, Major Customer [Line Items]
Customer Revenue	69,200		85,800		58,000
East Kentucky Power Cooperative [Member]
Revenue, Major Customer [Line Items]
Customer Revenue	41,400		56,600		43,700
Big Rivers Electric [Member]
Revenue, Major Customer [Line Items]
Customer Revenue		[1]		[1]	$ 44,000

[1] Sales to this customer were less than 10% in the respective year.

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Note 15 - Workers' Compensation and Black Lung (Details) (USD $) In Millions, unless otherwise specified	12 Months Ended
	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
Note 15 - Workers' Compensation and Black Lung (Details) [Line Items]
Gross Sales Price Percentage	4.40%
Deep-Mined Coal [Member]
Note 15 - Workers' Compensation and Black Lung (Details) [Line Items]
Excise Tax (in Dollars per Item)	1.10
Surface-Mined Coal [Member]
Note 15 - Workers' Compensation and Black Lung (Details) [Line Items]
Excise Tax (in Dollars per Item)	0.55
Excise Tax [Member]
Note 15 - Workers' Compensation and Black Lung (Details) [Line Items]
Cost of Goods Sold	$ 3.2	$ 3.6	$ 4.2

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Note 12 - Long-Term Incentive Plan (Details) (Restricted Stock Units (RSUs) [Member], USD $) In Thousands, except Share data, unless otherwise specified	1 Months Ended		12 Months Ended
	Jan. 31, 2014 Subsequent Event [Member] Long Term Incentive [Member]	Dec. 31, 2013 Long Term Incentive [Member]	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
Note 12 - Long-Term Incentive Plan (Details) [Line Items]
Share-based Compensation Arrangement by Share-based Payment Award, Award Vesting Period			4 years
Allocated Share-based Compensation Expense			$ 1,441	$ 1,262	$ 1,077
Employee Service Share-based Compensation, Nonvested Awards, Compensation Cost Not yet Recognized			2,150	1,843
Employee Service Share-based Compensation, Nonvested Awards, Compensation Cost Not yet Recognized, Period for Recognition			1 year 73 days
Stock Issued During Period, Value, Restricted Stock Award, Gross			$ 963	$ 944	$ 908
Share-based Compensation Arrangement by Share-based Payment Award, Number of Shares Authorized (in Shares)		2,056,075
Share-based Compensation Arrangement by Share-based Payment Award, Number of Shares Available for Grant (in Shares)	468,148	1,064,001
Share-based Compensation Arrangement by Share-based Payment Award, Number of Additional Shares Authorized (in Shares)	750,000
Share-based Compensation Arrangement by Share-based Payment Award, Equity Instruments Other than Options, Grants in Period (in Shares)	1,347,502		438,990,000	312,138,000

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Note 19 - Related Party Transactions

12 Months Ended

Dec. 31, 2013

Related Party Transactions [Abstract]

Related Party Transactions Disclosure [Text Block]

NOTE 19: RELATED PARTY TRANSACTIONS

In connection with our formation in August 2007, the Partnership and Oxford Mining entered into an administrative and operational services agreement (the “Services Agreement”) with our GP. The Services Agreement is terminable by either party upon thirty days’ written notice. Under the terms of the Services Agreement, our GP provides services through its employees to us and is reimbursed for all related costs incurred on our behalf. Our GP provides us with services such as general administrative and management, human resources, legal, information technology, finance and accounting, corporate development, real property, marketing, engineering, operations (including mining operations), geological, risk management and insurance services. Pursuant to the Services Agreement, the primary reimbursements to our GP were for costs related to payroll. Reimbursable costs under the Services Agreement totaling $624 and $3,442 were included in accounts payable as of December 31, 2013 and 2012, respectively.

We sell clay and small quantities of coal to Tunnell Hill Reclamation, LLC (“Tunnell Hill”), a company that is indirectly owned by Mr. C. Ungurean, Mr. T. Ungurean, and affiliates of AIM Oxford. We sold equipment to Tunnell Hill for $877 in 2012. Sales to Tunnell Hill were $385, $205 and $1,525 for the years ended December 31, 2013, 2012 and 2011, respectively. Accounts receivable from Tunnell Hill were $83 and a de minimis amount for the years ended December 31, 2013 and 2012, respectively.

From time to time for business purposes, we charter the use of various airplanes from Zanesville Aviation located in Zanesville, Ohio. Additionally, C&T owns an airplane that it leases to Zanesville Aviation and Zanesville Aviation uses that airplane in providing charter services to its customers, including us at times. During the years of 2013, 2012 and 2011, we paid Zanesville Aviation an aggregate of $97, $146 and $178, respectively.

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Note 3 - Impairment and Restructuring Expenses (Details) - Restructuring Accrual Activity (USD $) In Thousands, unless otherwise specified	12 Months Ended
	Dec. 31, 2013	Dec. 31, 2012
Note 3 - Impairment and Restructuring Expenses (Details) - Restructuring Accrual Activity [Line Items]
Liability	$ 656	$ 443
Expense	1,800	2,900
Payments	(865)
Total cash restructuring expenses	656	443
Total cash restructuring expenses	1,078
Total cash restructuring expenses	(865)
Employee Severance [Member]
Note 3 - Impairment and Restructuring Expenses (Details) - Restructuring Accrual Activity [Line Items]
Liability	404	405
Expense	534
Payments	(535)
Total cash restructuring expenses	404	405
Total cash restructuring expenses	(535)
Other Restructuring [Member]
Note 3 - Impairment and Restructuring Expenses (Details) - Restructuring Accrual Activity [Line Items]
Liability		18
Expense	26
Payments	(44)
Total cash restructuring expenses		18
Total cash restructuring expenses	(44)
Equipment Relocation Costs [Member]
Note 3 - Impairment and Restructuring Expenses (Details) - Restructuring Accrual Activity [Line Items]
Liability	252	20
Expense	495
Payments	(263)
Total cash restructuring expenses	252	20
Total cash restructuring expenses	(263)
Contract Termination [Member]
Note 3 - Impairment and Restructuring Expenses (Details) - Restructuring Accrual Activity [Line Items]
Expense	23
Payments	(23)
Total cash restructuring expenses	$ (23)

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Note 14 - Noncontrolling Interest (Tables)

12 Months Ended

Dec. 31, 2013

Noncontrolling Interest [Abstract]

Noncontrolling Interest [Table Text Block]

	For the Year Ended December 31,
	2013		2012
Beginning balance	$	3,744	$	2,989
Net income		1,225		755
Ending balance	$	4,969	$	3,744

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Note 14 - Noncontrolling Interest (Details) (USD $) In Thousands, unless otherwise specified	12 Months Ended
	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
Noncontrolling Interest [Abstract]
Equity Method Investment, Summarized Financial Information, Revenue	$ 34,100	$ 34,518	$ 38,664
Restricted Cash and Investments	3,969	3,929
Equity Method Investment, Summarized Financial Information, Assets	$ 10,140	$ 7,641
Noncontrolling Interest, Ownership Percentage by Noncontrolling Owners	49.00%

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Note 9 - Reclamation and Mine Closure Costs (Tables)

12 Months Ended

Dec. 31, 2013

Asset Retirement Obligation Disclosure [Abstract]

Schedule of Change in Asset Retirement Obligation [Table Text Block]

	Year Ended December 31,
	2013			2012
Beginning balance	$	29,013		$	21,789
Accretion expense		2,293			1,567
Payments		(8,656	)		(8,966	)
Revisions in estimated cash flows		9,004			14,623
Total reclamation and mine closure costs		31,654			29,013
Less current portion		(5,996	)		(3,869	)
Noncurrent liability	$	25,658		$	25,144

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Note 4 - Inventory (Details) - Inventory (USD $) In Thousands, unless otherwise specified	Dec. 31, 2013	Dec. 31, 2012
Inventory [Abstract]
Coal	$ 5,957	$ 5,609
Fuel	1,879	1,893
Spare parts and supplies	6,004	5,052
Total	$ 13,840	$ 12,554

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Note 10 - Long-Term Debt (Details) - Total Debt of Partnership (USD $) In Thousands, unless otherwise specified	Dec. 31, 2013
Total Debt of Partnership [Abstract]
During the years ending December 31, 2014	$ 7,901
2015	155,375
	$ 163,276

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Note 8 - Other Long-term Assets and Other Current Liabilities (Details) - Other Long-term Assets (USD $) In Thousands, unless otherwise specified	Dec. 31, 2013	Dec. 31, 2012
Note 8 - Other Long-term Assets and Other Current Liabilities (Details) - Other Long-term Assets [Line Items]
Other long-term assets	$ 22,821	$ 7,177
Reclamation Bond Collateral [Member]
Note 8 - Other Long-term Assets and Other Current Liabilities (Details) - Other Long-term Assets [Line Items]
Other long-term assets	9,582
Deferred Financing Costs, Net [Member]
Note 8 - Other Long-term Assets and Other Current Liabilities (Details) - Other Long-term Assets [Line Items]
Other long-term assets	7,644	2,061
Restricted Cash [Member]
Note 8 - Other Long-term Assets and Other Current Liabilities (Details) - Other Long-term Assets [Line Items]
Other long-term assets	3,969	3,929
Deposits [Member]
Note 8 - Other Long-term Assets and Other Current Liabilities (Details) - Other Long-term Assets [Line Items]
Other long-term assets	1,526	1,070
Other Long-Term Assets [Member]
Note 8 - Other Long-term Assets and Other Current Liabilities (Details) - Other Long-term Assets [Line Items]
Other long-term assets	$ 100	$ 117

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Note 2 - Summary of Significant Accounting Policies (Details) (USD $)	12 Months Ended
	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011	Dec. 31, 2010
Note 2 - Summary of Significant Accounting Policies (Details) [Line Items]
Net Income (Loss), Including Portion Attributable to Noncontrolling Interest	$ (23,700,000)	$ (26,053,000)	$ (8,329,000)
Partners' Capital	(10,998,000)	11,327,000	59,117,000	108,763,000
Net Cash Provided by (Used in) Operating Activities	9,676,000	33,587,000	41,288,000
Net Cash Provided by (Used in) Financing Activities	2,309,000	(22,772,000)	(947,000)
Available Liquidity	8,200,000
Cash and Cash Equivalents, at Carrying Value	3,089,000	3,977,000	3,032,000	889,000
Line of Credit Facility, Remaining Borrowing Capacity	5,100,000
Restricted Cash and Investments, Noncurrent	3,969,000	3,929,000
Proceeds from Royalties Received	8,000	1,496,000	3,202,000
Advance Royalties		2,200,000
Amortization Of Below Market Coal Sales Contracts	60,000	623,000	939,000
Long Term Debt Current [Member]
Note 2 - Summary of Significant Accounting Policies (Details) [Line Items]
Prior Period Reclassification Adjustment	$ 6,000,000
Unhedged Diesel Fuel Gallons [Member]
Note 2 - Summary of Significant Accounting Policies (Details) [Line Items]
Derivative, Nonmonetary Notional Amount, Percent of Required Need, Coverage	80.00%
Maximum [Member] | Forward Fuel Contract [Member]
Note 2 - Summary of Significant Accounting Policies (Details) [Line Items]
Derivative, Term of Contract	1 year

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Note 3 - Impairment and Restructuring Expenses

12 Months Ended

Dec. 31, 2013

Restructuring and Related Activities [Abstract]

Restructuring and Related Activities Disclosure [Text Block]

NOTE 3: IMPAIRMENT AND RESTRUCTURING EXPENSES

In March 2012, we received a termination notice from a customer related to an 0.8 million ton per year coal supply contract fulfilled from our Illinois Basin operations. In response, we idled one Illinois Basin mine and the related preparation plant, closed our Illinois Basin lab, reduced operations at two other mines, terminated a significant number of employees and substituted purchased coal for mined coal on certain sales contracts. Operations at the two remaining mines varied to best manage strip ratio impacts and other costs through early December 2013, at which time all production was discontinued. As of December 31, 2013, we have sold or redeployed almost all of the Illinois Basin equipment to our Northern Appalachian operations. 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 to purchase the remaining coal reserves and/or facilities related to our Illinois Basin operations.

Impairment Expenses

As a result of the restructuring described above, we recorded asset impairment expenses of $12.8 million during 2012. These non-cash expenses related to coal reserves, mine development assets and certain mining equipment (the “Impaired Assets”). No such expenses were recorded in the year ended December 31, 2013.

In determining our impairment expenses, we utilized market prices for similar assets and discounted projected future cash flows to determine the fair value of the Impaired Assets. Our discounted projected future cash flows were based on financial forecasts developed internally for planning purposes. These projections incorporated certain assumptions, including future costs and sales trends, estimated costs to sell and our expected net realizable values for the Impaired Assets. As of December 31, 2012, the Impaired Assets that we planned to sell, and were no longer in production, were presented separately as current assets held for sale in our consolidated balance sheet. Such Impaired Assets were recorded at carrying value, after taking into account the impairment. The Impaired Assets were not depreciated or amortized during the last nine months of 2012 and the first three months of 2013. Assets held for sale totaling $6.1 million that were not sold as of March 31, 2013 were reclassified from assets held for sale to machinery and equipment at that date.

Restructuring Expenses

Restructuring expenses related to our Illinois Basin operations totaled $1.8 and $2.9 million for the years ended December 31, 2013 and 2012, respectively. These expenses included termination costs for approximately 200 employees in 2012, and 35 employees in 2013, professional and legal fees and transportation costs associated with moving idled Illinois Basin equipment to our Northern Appalachian operations. In addition, we terminated one coal lease and wrote off the related asset in the second quarter of 2013. We expect to incur $0.1 million of additional costs during 2014 as we complete the restructuring. The liabilities related to the restructuring are included in “other current liabilities” in our consolidated balance sheets as of December 31, 2013 and 2012.

Restructuring accrual activity, combined with a reconciliation to “impairment and restructuring expenses” as set forth in our consolidated statements of operations, is summarized as follows:

	As of December 31, 2012		For the Twelve Months Ended December 31, 2013					As of December 31, 2013
	Liability		Expense		Payments			Liability
Severance and other termination costs	$	405	$	534	$	(535	)	$	404
Professional and legal fees		18		26		(44	)		-
Equipment relocation costs		20		495		(263	)		252
Coal lease termination costs		-		23		(23	)		-
Total cash restructuring expenses	$	443	$	1,078	$	(865	)	$	656

The following table summarizes the total impairment and restructuring expenses expected to be incurred over the course of the restructuring:

	Expenses
	For the Twelve Months Ended December 31, 2013		Incurred Through December 31, 2013		Total Expected Expenses
Cash:
Severance and other termination costs	$	534	$	1,887	$	1,887
Professional and legal fees		26		1,021		1,021
Equipment relocation costs		495		1,044		1,178
Coal lease termination costs		23		23		23
Total cash restructuring expenses		1,078		3,975		4,109
Non-cash:
Coal lease termination costs		683		683		683
Asset impairment		-		12,753		12,753
Total non-cash restructuring expenses		683		13,436		13,436
Total impairment and restructuring expenses	$	1,761	$	17,411	$	17,545

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Note 8 - Other Long-term Assets and Other Current Liabilities (Details) - Other Current Liabilities (USD $) In Thousands, unless otherwise specified	Dec. 31, 2013		Dec. 31, 2012
Note 8 - Other Long-term Assets and Other Current Liabilities (Details) - Other Current Liabilities [Line Items]
Other Liabilities, Current	$ 3,457		$ 2,491
Accrued Interest and Interest Rate Swap [Member]
Note 8 - Other Long-term Assets and Other Current Liabilities (Details) - Other Current Liabilities [Line Items]
Other Liabilities, Current	1,424	[1]	709	[1]
Accrued Royalties [Member]
Note 8 - Other Long-term Assets and Other Current Liabilities (Details) - Other Current Liabilities [Line Items]
Other Liabilities, Current	1,062		815
Other Current Liabilities [Member]
Note 8 - Other Long-term Assets and Other Current Liabilities (Details) - Other Current Liabilities [Line Items]
Other Liabilities, Current	$ 971		$ 967

[1] See Note 11 regarding interest rate swap.

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Note 18 - Concentration of Credit Risk and Major Customers (Tables)

12 Months Ended

Dec. 31, 2013

Risks and Uncertainties [Abstract]

Schedule of Revenue by Major Customers by Reporting Segments [Table Text Block]

	Revenues for the Year Ended December 31,
Customer	2013		2012		2011
	(in millions)
American Electric Power	$	146.3	$	128.8	$	139.7
First Energy		69.2		85.8		58.0
East Kentucky Power Cooperative		41.4		56.6		43.7
Big Rivers Electric		*		*		44.0

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Accounting Policies, by Policy (Policies)

12 Months Ended

Dec. 31, 2013

Accounting Policies [Abstract]

Use of Estimates, Policy [Policy Text Block]

Use of Estimates

Our financial statements are prepared in accordance with US GAAP. The preparation of these financial statements require management to make estimates and assumptions that affect the reported amounts of assets, liabilities, revenues and expenses, as well as the disclosures of contingent assets and liabilities (if any).

The most significant policies requiring the use of management estimates and assumptions relate to collectability of accounts receivable, useful lives of fixed assets, valuation of coal reserves, amortization calculations using the units-of-production method, reserve estimates of coal reserves, evaluations of asset impairment, recoverability of advance royalties, useful lives of intangible assets, and estimates of future reclamation and mine closure costs. The estimates and assumptions that we use are based upon our evaluation of the relevant facts and circumstances as of the date of the financial statements. Actual results could differ significantly from those estimates.

Liquidity Disclosure [Policy Text Block]

Liquidity

The accompanying consolidated financial statements have been prepared assuming that we will continue as a going concern.  We have incurred net losses of $23,700, $26,053 and $8,329 for the years ended December 31, 2013, 2012, and 2011, respectively, resulting in an accumulated deficit of $10,998 at December 31, 2013. We have managed our liquidity for the year ended December 31, 2013, with $9,676 of cash flows provided from operations and $2,309 of cash flows provided from financing activities. As of December 31, 2013, our available liquidity was $8.2 million, which consisted of $3.1 million in cash on hand and $5.1 million of borrowing capacity under our credit facilities.

Should we have difficulty meeting our forecasts, this could have an adverse effect on our liquidity position. Management has taken the following actions to improve its liquidity position:

● restructured our Illinois Basin operations (see Note 3);

● aligned our coal production with our committed coal sales and reduced costs by temporarily idling production at two Northern Appalachian mines and eliminating approximately 50 positions;

● reduced capital expenditures; and

● acquired a strategically located coal preparation plant next to a significant customer that will reduce coal transportation costs.

Through the aforementioned actions, management expects to be able to achieve its forecasted results for the year ending December 31, 2014. However, there can be no assurance that our cash flows will be sufficient to allow us to continue as a going concern if we are unable to meet our projections.

Cash and Cash Equivalents, Policy [Policy Text Block]

Cash and Restricted Cash

Cash and restricted cash consist of cash held with reputable depository institutions. Cash and restricted cash are stated at cost, which approximates fair market value. At times, such deposits may be in excess of the FDIC insurance limit. We have not experienced any losses in such accounts and believe we are not exposed to any significant credit risk relating to such amounts.

We had restricted cash related to Harrison Resources of $3,969 and $3,929 as of December 31, 2013 and 2012, respectively, which are included in our consolidated balance sheets as “other long-term assets.” Harrison Resources’ cash, which is deemed to be restricted due to the limitations of its use for Harrison Resources’ operations, primarily relates to funds set aside for future reclamation obligations. See the Noncontrolling Interest section of this Note 2 and Note 14.

Financing Receivable, Allowance for Credit Losses, Policy or Methodology Change [Policy Text Block]

Allowance for Doubtful Accounts

We establish an allowance for losses on accounts receivable when it is probable that all or part of an outstanding balance will not be collected. Our management regularly reviews the probability that a receivable will be collected and establishes or adjusts the allowance as necessary. There was no allowance for doubtful accounts as of December 31, 2013 and 2012.

Inventory, Policy [Policy Text Block]

Inventory

Inventory consists of coal that has been completely uncovered or that has been removed from the pit and stockpiled for crushing, washing or shipment to customers. Inventory also consists of supplies, spare parts and fuel. Inventory is valued at the lower of average cost or market. The cost of coal inventory includes certain operating expenses including overhead and stripping costs incurred during the production phase, which commences when saleable coal, beyond a de minimis amount, is produced.

Property, Plant and Equipment, Policy [Policy Text Block]

Property, Plant and Equipment

Property, plant and equipment are recorded at cost. Expenditures that extend the useful lives of existing plant and equipment are capitalized. Maintenance and repairs that do not extend the useful life or increase productivity are charged to operating expense as incurred. Plant and equipment are depreciated principally on the straight-line method over the estimated useful lives of the assets based on the following schedule:

	Years
Buildings and tipple		25	-	39
Machinery and equipment		1	-	12
Vehicles		5	-	7
Furniture and fixtures		3	-	7
Railroad siding			7

We acquire our coal reserves through purchases or leases. We deplete our coal reserves using the units-of-production method on the basis of tonnage mined in relation to total estimated recoverable tonnage with residual surface values classified as land. As of December 31, 2013 and 2012, all of our Northern Appalachian reserves were attributed to mine complexes engaged in mining operations or leased to third parties. As of December 31, 2013, all Illinois Basin mining activities had been idled. Management would consider offers for the remaining coal reserves and/or facilities related to the Illinois Basin operations.

Exploration expenditures are charged to operating expense as incurred and include costs related to locating coal deposits and the drilling and evaluation costs incurred to assess the economic viability of such deposits. Costs incurred in areas outside the boundary of known coal deposits and areas with insufficient drilling to qualify as proven and probable reserves are also expensed as exploration costs.

Once management determines there is sufficient evidence that the expenditure will result in a future economic benefit to the Partnership, the costs are capitalized as mine development costs. Capitalization of mine development costs continues until more than a de minimis amount of saleable coal is extracted from the mine. Amortization of these mine development costs is then initiated using the units-of-production method based upon the total estimated recoverable tonnage.

Impairment or Disposal of Long-Lived Assets, Policy [Policy Text Block]

Long-Lived Assets and Asset Impairment

Long-lived assets, such as property, plant and equipment, coal reserves, mine development costs and intangible assets, are reviewed for impairment whenever events or changes in circumstances indicate that the carrying amount of an asset or asset group may not be recoverable. Recoverability is measured by comparing the projected future cash flows from use and disposition of assets with the carrying amounts of those assets. When the sum of projected cash flows is less than the carrying amount, impairment losses are indicated. If the fair value of the assets is less than the carrying amount thereof, an impairment loss is recognized. In determining such impairment losses, discounted cash flows or asset appraisals are utilized to determine the fair value of the assets being evaluated. Assets held for sale are reported at the lower of the carrying amount or fair value less costs to sell, and are no longer depreciated.

Also, in certain situations, expected mine lives are shortened because of changes to planned operations. When that occurs and it is determined that the mine’s underlying costs are not recoverable in the future, reclamation and mine closure obligations are accelerated by accelerating the depletion rate. To the extent it is determined that an asset’s carrying value will not be recoverable during a shorter mine life, the asset is written down to its recoverable value. There were no indicators of impairment present during the years ended December 31, 2013 and 2011. See Note 3 for discussion of impairment expenses in 2012.

Revenue Recognition, Services, Royalty Fees [Policy Text Block]

Advance Royalties

A substantial portion of our reserves are leased. Advance royalties are advance payments made to lessors under terms of lease agreements that are typically recoupable through an offset or credit against royalties payable on future production. We write-off advance royalties when recoverability is no longer probable based on future mining plans.

Deferred Charges, Policy [Policy Text Block]

Deferred Financing Costs

We capitalize costs incurred in connection with the establishment of credit facilities and amortize such costs to interest expense over the term of the credit facilities using the effective interest method.

Fair Value of Financial Instruments, Policy [Policy Text Block]

Financial Instruments and Derivative Financial Instruments

Our financial instruments include cash and restricted cash, accounts receivable, accounts payable, fixed rate debt and variable rate debt. In 2012, we also had an interest rate swap agreement. We do not hold or purchase financial instruments or derivative financial instruments for trading purposes.

Our financial instruments include fixed price forward contracts for diesel fuel. Our risk management policy allows us to purchase up to 80% of our unhedged diesel fuel gallons on fixed price forward contracts. These contracts meet the normal purchases and sales exclusion and therefore are not accounted for as derivatives. These forward fuel contracts usually have a term of one year or less, and we take physical delivery of all the fuel supplied under these contracts except in the case of one Illinois Basin contract which was modified.

Warrants [Policy Text Block]

Warrants

In conjunction with our refinancing in June 2013, certain of the second lien lenders and lender affiliates received warrants entitling them to purchase common and subordinated units under a freestanding contract. Pursuant to Financial Accounting Standards Board's Accounting Standards Board's Codification Topic 470-20, “Debt With Conversion and Other Options” (ASC 470-20), freestanding contracts that are settled in a company’s own stock, including common and subordinated unit warrants, are to be designated as an asset, liability or equity instrument. Both the common and subordinated unit warrants were determined to be liabilities and were recorded at fair value as determined using the Black-Scholes Pricing Model. ASC 470-20 further requires that the warrants' fair value be remeasured each reporting period, with the change in fair value being reported in the consolidated statements of operations. Fair value determinations prepared using the Black-Scholes Pricing Model require assumptions related to interest rates, unit price, exercise price, term and volatilities.

Goodwill and Intangible Assets, Policy [Policy Text Block]

Intangible Assets

We have recorded intangible assets associated with certain customer relationships at fair value. These balances arose from the purchase accounting for our acquisition of Oxford Mining and its subsidiaries. These intangible assets are being amortized over their expected useful lives and are recorded in “intangible assets, net” in our consolidated balance sheets. See Note 7 for further details.

Asset Retirement Obligations, Policy [Policy Text Block]

Reclamation and Mine Closure Costs

Our reclamation and mine closure costs arise from the Surface Mining Control and Reclamation Act (“SMCRA”) and similar state statutes, which require that mine property be restored in accordance with specified standards and an approved reclamation plan. Our reclamation and mine closure costs are recorded initially at fair value based on the assumption that all work will be performed by third-party contractors. We estimate reclamation and mine closure costs using the end of mine life method. The end of mine life method estimates the liability based on the costs to reclaim the last pit(s) once the mine is no longer producing coal. This liability is amortized over the tons expected to be recovered over the productive life of the mine.

To determine the fair value of our reclamation and mine closure costs, we calculate on a mine-by-mine basis the present value of estimated reclamation cash flows. This process requires us to estimate the acreage subject to reclamation, estimate future reclamation costs, and make assumptions regarding the mine’s productivity. These cash flows are discounted at a credit-adjusted, risk-free interest rate based on U.S. Treasury bonds with a maturity similar to the expected lives of the mines.

When the liability is initially established, the offset is capitalized to the mine development asset. Over time, the reclamation and mine closure cost liability is accreted to its present value, and the capitalized cost is depleted using the units-of-production method for the related mine. If the assumptions used to estimate the reclamation and mine closure cost liability do not materialize as expected or regulatory changes occur, reclamation costs or obligations to perform reclamation and mine closure activities could be materially different than initially estimated. At least annually, we review our reclamation liability and make adjustments for permit changes, cost revisions, changes to mining plans and the timing of expenditures. See Note 9.

Income Tax, Policy [Policy Text Block]

Income Taxes

As a partnership, we are not a taxable entity for federal or state income tax purposes; the tax effect of our activities passes through to our unitholders. Therefore, no provision or liability for federal or state income taxes is included in our financial statements. Net income (loss) for financial statement purposes may differ significantly from taxable income (loss) reportable to our unitholders as a result of timing or permanent differences between financial reporting under US GAAP and the regulations promulgated by the Internal Revenue Service.

Revenue Recognition, Policy [Policy Text Block]

Revenue Recognition

Revenue from coal sales is recognized and recorded when shipment or delivery to the customer has occurred, prices are fixed or determinable, and the title or risk of loss has passed. Coal sales prices are subject to premiums and reductions based on variations in coal quality delivered versus specifications in our coal supply contracts, but such adjustments are typically confirmed in a matter of days. Risk of loss typically transfers to the customer at the mine or dock, when the coal is loaded on the rail, barge, or truck.

Other revenue consists primarily of clay and limestone sales, royalty income, service fees, and other miscellaneous revenue. Clay and limestone sales relate to material we recover during the coal mining process and sell to third parties. Royalty income relates to underground coal reserves that we sublease to a third party mining company. For the years ended 2013, 2012 and 2011, we received royalties of $8, $1,496 and $3,202, respectively. In 2012, we received an advance payment of $2.2 million for these royalties in exchange for a significant reduction in the amount of the overriding royalty going forward. Service fees are earned for operating a coal unloading facility, providing river barge loading services, and hauling ash. Periodically, we recognize miscellaneous revenue related to lost coal claims that result from granting third-party right-of-way access through small portions of various mine complexes.

Below Market Coal Sales Contracts [Policy Text Block]

Below-Market Coal Sales Contracts

Our below-market coal sales contracts were acquired through the Phoenix Coal acquisition in 2009 and represent contracts for which the prevailing market price for the specified coal was in excess of the contract price. The fair value was based on discounted cash flows resulting from the difference between the below-market contract price and the prevailing market price at the date of acquisition. The fair value adjustments are amortized into coal sales on the basis of tons shipped over the terms of the respective contracts. Amortization of these below-market contracts included in revenue was $60, $623 and $939 for the years ended December 31, 2013, 2012 and 2011, respectively. The current portion of the net carrying value of our below-market coal sales contracts was reflected in our consolidated balance sheets as “other current liabilities.” No such amounts remained at December 31, 2013.

Share-based Compensation, Option and Incentive Plans Policy [Policy Text Block]

Equity-Based Compensation

We account for equity-based awards in accordance with applicable guidance, which establishes standards of accounting for transactions in which an entity exchanges its equity instruments for goods or services. Equity-based compensation expense is recorded based upon the fair value of the award at grant date. The fair value of our LTIP units is determined based on the closing sales price of our units on the New York Stock Exchange on the grant date. The related expense is recognized on a straight-line basis over the corresponding vesting period. See Note 12.

Consolidation, Subsidiaries or Other Investments, Consolidated Entities, Policy [Policy Text Block]

Noncontrolling Interest

US GAAP requires noncontrolling interests to be reported as a separate component of equity. The amount of net income attributable to the noncontrolling interests is recorded in “net income attributable to noncontrolling interest” in our consolidated statements of operations. See Note 14.

Earnings Per Share, Policy [Policy Text Block]

Earnings (Losses) Per Unit

For purposes of our earnings per unit calculation, we apply the two class method. All outstanding limited partner units and general partner units share pro rata in income (loss) allocations and distributions, but only our general partner has voting rights. Limited partner units are further segregated into common units and subordinated units.

Limited Partner Units: Basic earnings (losses) per unit are computed by dividing net income (loss) attributable to limited partners by the weighted average units outstanding, including unexercised participating warrants, during the reporting period. Diluted earnings (losses) per unit are computed similar to basic earnings (losses) per unit except that the weighted average units outstanding and net income (loss) attributable to limited partners are increased to include phantom units that have not yet vested and that will convert to limited partnership units upon vesting. In periods of a loss, the phantom units are anti-dilutive and therefore not included in the earnings (losses) per unit calculation.

General Partner Units: Basic earnings (losses) per unit are computed by dividing net income (loss) attributable to our GP by the weighted average units outstanding, including unexercised participating warrants, during the reporting period. Diluted earnings (losses) per unit for our GP are computed similar to basic earnings (losses) per unit except that the net income (loss) attributable to the general partner units is adjusted for the dilutive impact of the phantom units. In periods of a loss, the phantom units are anti-dilutive and therefore not included in the earnings (losses) per unit calculation.

New Accounting Pronouncements, Policy [Policy Text Block]

New Accounting Standards Issued

There were various updates recently issued, most of which represented technical corrections to the accounting literature or application to specific industries. We do not believe that the adoption of the guidance provided by these updates will have a material impact on our consolidated financial statements.

Reclassification, Policy [Policy Text Block]

Reclassifications

Certain prior-year amounts have been reclassified in our consolidated balance sheet as of December 31, 2012. Payments due on the term note of $6 million have been reclassified from “long-term debt” to “current portion of long-term debt.”

Certain prior-year amounts have been reclassified in our consolidated statements of cash flows to conform with current-year classifications. These reclassifications are to reclassify “change in restricted cash” in “Cash Flows From Investing Activities” to “restricted cash” in “Cash Flows From Operating Activities.”

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Note 22 - Supplemental Quarter Financial Information (Unaudited)

12 Months Ended

Dec. 31, 2013

Quarterly Financial Information Disclosure [Abstract]

Quarterly Financial Information [Text Block]

NOTE 22: SUPPLEMENTAL QUARTERLY FINANCIAL INFORMATION - (Unaudited)

A summary of our unaudited consolidated quarterly operating results in 2013 and 2012 is as follows:

	2013
	March 31			June 30			September 30			December 31			Total
Total revenues	$	88,726		$	88,125		$	87,586		$	82,330		$	346,767
Net (loss) income from operations		(3,356	)		2,434			(1,036	)		(3,972	)		(5,930	)
Net loss attributable to Oxford Resource
Partners, LP unitholders		(6,547	)		(4,510	)		(5,599	)		(8,269	)		(24,925	)
Net loss allocated to general partner		(131	)		(89	)		(112	)		(165	)		(497	)
Net loss allocated to limited partners		(6,416	)		(4,421	)		(5,487	)		(8,104	)		(24,428	)
Loss per limited partner unit:
Basic	$	(0.31	)	$	(0.21	)	$	(0.22	)	$	(0.33	)	$	(1.07	)
Diluted	$	(0.31	)	$	(0.21	)	$	(0.22	)	$	(0.33	)	$	(1.07	)
Distributions paid per unit:
Limited partners:
Common	$	-		$	-		$	-		$	-		$	-
Subordinated	$	-		$	-		$	-		$	-		$	-
General partner	$	-		$	-		$	-		$	-		$	-

	2012
	March 31			June 30			September 30			December 31			Total
Total revenues	$	97,867		$	91,948		$	97,214		$	86,498		$	373,527
Net (loss) income from operations		(12,968	)		1,338			(29	)		(2,904	)		(14,563	)
Net loss attributable to Oxford Resource
Partners, LP unitholders		(15,776	)		(1,455	)		(3,314	)		(6,263	)		(26,808	)
Net loss allocated to general partner		(315	)		(29	)		(66	)		(125	)		(535	)
Net loss allocated to limited partners		(15,461	)		(1,426	)		(3,248	)		(6,138	)		(26,273	)
Loss per limited partner unit:
Basic	$	(0.75	)	$	(0.07	)	$	(0.16	)	$	(0.29	)	$	(1.27	)
Diluted	$	(0.75	)	$	(0.07	)	$	(0.16	)	$	(0.29	)	$	(1.27	)
Distributions paid per unit:
Limited partners:
Common	$	0.4375		$	0.4375		$	0.4375		$	0.2000		$	1.5125
Subordinated	$	0.4375		$	0.1000		$	0.1000		$	-		$	0.6375
General partner	$	0.4375		$	0.2688		$	0.2688		$	0.1000		$	1.0750

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Note 6 - Operating Leases (Details) (USD $) In Thousands, unless otherwise specified	12 Months Ended
	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
Note 6 - Operating Leases (Details) [Line Items]
Operating Leases, Rent Expense	$ 8,591	$ 7,118	$ 3,383
Minimum [Member]
Note 6 - Operating Leases (Details) [Line Items]
Lessee Leasing Arrangements, Operating Leases, Term of Contract	3 years
Maximum [Member]
Note 6 - Operating Leases (Details) [Line Items]
Lessee Leasing Arrangements, Operating Leases, Term of Contract	10 years

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Note 20 - Supplemental Cash Flow Information (Tables)

12 Months Ended

Dec. 31, 2013

Supplemental Cash Flow Elements [Abstract]

Schedule of Cash Flow, Supplemental Disclosures [Table Text Block]

	For the Year Ended December 31,
	2013		2012		2011
Cash paid for:
Interest	$	12,258	$	10,739	$	6,976
Non-cash activities:
Coal reserves acquired with debt		-		307		-
Property and equipment acquired with debt		1,000		-		-
Reclamation and mine closure costs capitalized in mine development		8,927		16,011		12,278
Value of debt assigned to warrants		7,879		-		-
Market value of common units vested in LTIP		330		849		2,055

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Note 2 - Summary of Significant Accounting Policies (Tables)

12 Months Ended

Dec. 31, 2013

Accounting Policies [Abstract]

Property, Plant and Equipment, Estimated Useful Lives

	Years
Buildings and tipple		25	-	39
Machinery and equipment		1	-	12
Vehicles		5	-	7
Furniture and fixtures		3	-	7
Railroad siding			7

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Note 3 - Impairment and Restructuring Expenses (Tables)

12 Months Ended

Dec. 31, 2013

Restructuring and Related Activities [Abstract]

Schedule of Restructuring Reserve by Type of Cost [Table Text Block]

	As of December 31, 2012		For the Twelve Months Ended December 31, 2013					As of December 31, 2013
	Liability		Expense		Payments			Liability
Severance and other termination costs	$	405	$	534	$	(535	)	$	404
Professional and legal fees		18		26		(44	)		-
Equipment relocation costs		20		495		(263	)		252
Coal lease termination costs		-		23		(23	)		-
Total cash restructuring expenses	$	443	$	1,078	$	(865	)	$	656

Schedule of Impairment and Restructuring Expenses Incurred and Expected To Be Incurred [Table Text Block]

	Expenses
	For the Twelve Months Ended December 31, 2013		Incurred Through December 31, 2013		Total Expected Expenses
Cash:
Severance and other termination costs	$	534	$	1,887	$	1,887
Professional and legal fees		26		1,021		1,021
Equipment relocation costs		495		1,044		1,178
Coal lease termination costs		23		23		23
Total cash restructuring expenses		1,078		3,975		4,109
Non-cash:
Coal lease termination costs		683		683		683
Asset impairment		-		12,753		12,753
Total non-cash restructuring expenses		683		13,436		13,436
Total impairment and restructuring expenses	$	1,761	$	17,411	$	17,545

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Note 2 - Summary of Significant Accounting Policies

12 Months Ended

Dec. 31, 2013

Accounting Policies [Abstract]

Significant Accounting Policies [Text Block]

NOTE 2:   SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

Use of Estimates

Our financial statements are prepared in accordance with US GAAP. The preparation of these financial statements require management to make estimates and assumptions that affect the reported amounts of assets, liabilities, revenues and expenses, as well as the disclosures of contingent assets and liabilities (if any).

The most significant policies requiring the use of management estimates and assumptions relate to collectability of accounts receivable, useful lives of fixed assets, valuation of coal reserves, amortization calculations using the units-of-production method, reserve estimates of coal reserves, evaluations of asset impairment, recoverability of advance royalties, useful lives of intangible assets, and estimates of future reclamation and mine closure costs. The estimates and assumptions that we use are based upon our evaluation of the relevant facts and circumstances as of the date of the financial statements. Actual results could differ significantly from those estimates.

Liquidity

The accompanying consolidated financial statements have been prepared assuming that we will continue as a going concern.  We have incurred net losses of $23,700, $26,053 and $8,329 for the years ended December 31, 2013, 2012, and 2011, respectively, resulting in an accumulated deficit of $10,998 at December 31, 2013. We have managed our liquidity for the year ended December 31, 2013, with $9,676 of cash flows provided from operations and $2,309 of cash flows provided from financing activities. As of December 31, 2013, our available liquidity was $8.2 million, which consisted of $3.1 million in cash on hand and $5.1 million of borrowing capacity under our credit facilities.

Should we have difficulty meeting our forecasts, this could have an adverse effect on our liquidity position. Management has taken the following actions to improve its liquidity position:

● restructured our Illinois Basin operations (see Note 3);

● aligned our coal production with our committed coal sales and reduced costs by temporarily idling production at two Northern Appalachian mines and eliminating approximately 50 positions;

● reduced capital expenditures; and

● acquired a strategically located coal preparation plant next to a significant customer that will reduce coal transportation costs.

Through the aforementioned actions, management expects to be able to achieve its forecasted results for the year ending December 31, 2014. However, there can be no assurance that our cash flows will be sufficient to allow us to continue as a going concern if we are unable to meet our projections.

Cash and Restricted Cash

Cash and restricted cash consist of cash held with reputable depository institutions. Cash and restricted cash are stated at cost, which approximates fair market value. At times, such deposits may be in excess of the FDIC insurance limit. We have not experienced any losses in such accounts and believe we are not exposed to any significant credit risk relating to such amounts.

We had restricted cash related to Harrison Resources of $3,969 and $3,929 as of December 31, 2013 and 2012, respectively, which are included in our consolidated balance sheets as “other long-term assets.” Harrison Resources’ cash, which is deemed to be restricted due to the limitations of its use for Harrison Resources’ operations, primarily relates to funds set aside for future reclamation obligations. See the Noncontrolling Interest section of this Note 2 and Note 14.

Allowance for Doubtful Accounts

We establish an allowance for losses on accounts receivable when it is probable that all or part of an outstanding balance will not be collected. Our management regularly reviews the probability that a receivable will be collected and establishes or adjusts the allowance as necessary. There was no allowance for doubtful accounts as of December 31, 2013 and 2012.

Inventory

Inventory consists of coal that has been completely uncovered or that has been removed from the pit and stockpiled for crushing, washing or shipment to customers. Inventory also consists of supplies, spare parts and fuel. Inventory is valued at the lower of average cost or market. The cost of coal inventory includes certain operating expenses including overhead and stripping costs incurred during the production phase, which commences when saleable coal, beyond a de minimis amount, is produced.

Property, Plant and Equipment

Property, plant and equipment are recorded at cost. Expenditures that extend the useful lives of existing plant and equipment are capitalized. Maintenance and repairs that do not extend the useful life or increase productivity are charged to operating expense as incurred. Plant and equipment are depreciated principally on the straight-line method over the estimated useful lives of the assets based on the following schedule:

	Years
Buildings and tipple		25	-	39
Machinery and equipment		1	-	12
Vehicles		5	-	7
Furniture and fixtures		3	-	7
Railroad siding			7

We acquire our coal reserves through purchases or leases. We deplete our coal reserves using the units-of-production method on the basis of tonnage mined in relation to total estimated recoverable tonnage with residual surface values classified as land. As of December 31, 2013 and 2012, all of our Northern Appalachian reserves were attributed to mine complexes engaged in mining operations or leased to third parties. As of December 31, 2013, all Illinois Basin mining activities had been idled. Management would consider offers for the remaining coal reserves and/or facilities related to the Illinois Basin operations.

Exploration expenditures are charged to operating expense as incurred and include costs related to locating coal deposits and the drilling and evaluation costs incurred to assess the economic viability of such deposits. Costs incurred in areas outside the boundary of known coal deposits and areas with insufficient drilling to qualify as proven and probable reserves are also expensed as exploration costs.

Once management determines there is sufficient evidence that the expenditure will result in a future economic benefit to the Partnership, the costs are capitalized as mine development costs. Capitalization of mine development costs continues until more than a de minimis amount of saleable coal is extracted from the mine. Amortization of these mine development costs is then initiated using the units-of-production method based upon the total estimated recoverable tonnage.

Long-Lived Assets and Asset Impairment

Long-lived assets, such as property, plant and equipment, coal reserves, mine development costs and intangible assets, are reviewed for impairment whenever events or changes in circumstances indicate that the carrying amount of an asset or asset group may not be recoverable. Recoverability is measured by comparing the projected future cash flows from use and disposition of assets with the carrying amounts of those assets. When the sum of projected cash flows is less than the carrying amount, impairment losses are indicated. If the fair value of the assets is less than the carrying amount thereof, an impairment loss is recognized. In determining such impairment losses, discounted cash flows or asset appraisals are utilized to determine the fair value of the assets being evaluated. Assets held for sale are reported at the lower of the carrying amount or fair value less costs to sell, and are no longer depreciated.

Also, in certain situations, expected mine lives are shortened because of changes to planned operations. When that occurs and it is determined that the mine’s underlying costs are not recoverable in the future, reclamation and mine closure obligations are accelerated by accelerating the depletion rate. To the extent it is determined that an asset’s carrying value will not be recoverable during a shorter mine life, the asset is written down to its recoverable value. There were no indicators of impairment present during the years ended December 31, 2013 and 2011. See Note 3 for discussion of impairment expenses in 2012.

Advance Royalties

A substantial portion of our reserves are leased. Advance royalties are advance payments made to lessors under terms of lease agreements that are typically recoupable through an offset or credit against royalties payable on future production. We write-off advance royalties when recoverability is no longer probable based on future mining plans.

Deferred Financing Costs

We capitalize costs incurred in connection with the establishment of credit facilities and amortize such costs to interest expense over the term of the credit facilities using the effective interest method.

Financial Instruments and Derivative Financial Instruments

Our financial instruments include cash and restricted cash, accounts receivable, accounts payable, fixed rate debt and variable rate debt. In 2012, we also had an interest rate swap agreement. We do not hold or purchase financial instruments or derivative financial instruments for trading purposes.

Our financial instruments include fixed price forward contracts for diesel fuel. Our risk management policy allows us to purchase up to 80% of our unhedged diesel fuel gallons on fixed price forward contracts. These contracts meet the normal purchases and sales exclusion and therefore are not accounted for as derivatives. These forward fuel contracts usually have a term of one year or less, and we take physical delivery of all the fuel supplied under these contracts except in the case of one Illinois Basin contract which was modified.

Warrants

In conjunction with our refinancing in June 2013, certain of the second lien lenders and lender affiliates received warrants entitling them to purchase common and subordinated units under a freestanding contract. Pursuant to Financial Accounting Standards Board's Accounting Standards Board's Codification Topic 470-20, “Debt With Conversion and Other Options” (ASC 470-20), freestanding contracts that are settled in a company’s own stock, including common and subordinated unit warrants, are to be designated as an asset, liability or equity instrument. Both the common and subordinated unit warrants were determined to be liabilities and were recorded at fair value as determined using the Black-Scholes Pricing Model. ASC 470-20 further requires that the warrants' fair value be remeasured each reporting period, with the change in fair value being reported in the consolidated statements of operations. Fair value determinations prepared using the Black-Scholes Pricing Model require assumptions related to interest rates, unit price, exercise price, term and volatilities.

Intangible Assets

We have recorded intangible assets associated with certain customer relationships at fair value. These balances arose from the purchase accounting for our acquisition of Oxford Mining and its subsidiaries. These intangible assets are being amortized over their expected useful lives and are recorded in “intangible assets, net” in our consolidated balance sheets. See Note 7 for further details.

Reclamation and Mine Closure Costs

Our reclamation and mine closure costs arise from the Surface Mining Control and Reclamation Act (“SMCRA”) and similar state statutes, which require that mine property be restored in accordance with specified standards and an approved reclamation plan. Our reclamation and mine closure costs are recorded initially at fair value based on the assumption that all work will be performed by third-party contractors. We estimate reclamation and mine closure costs using the end of mine life method. The end of mine life method estimates the liability based on the costs to reclaim the last pit(s) once the mine is no longer producing coal. This liability is amortized over the tons expected to be recovered over the productive life of the mine.

To determine the fair value of our reclamation and mine closure costs, we calculate on a mine-by-mine basis the present value of estimated reclamation cash flows. This process requires us to estimate the acreage subject to reclamation, estimate future reclamation costs, and make assumptions regarding the mine’s productivity. These cash flows are discounted at a credit-adjusted, risk-free interest rate based on U.S. Treasury bonds with a maturity similar to the expected lives of the mines.

When the liability is initially established, the offset is capitalized to the mine development asset. Over time, the reclamation and mine closure cost liability is accreted to its present value, and the capitalized cost is depleted using the units-of-production method for the related mine. If the assumptions used to estimate the reclamation and mine closure cost liability do not materialize as expected or regulatory changes occur, reclamation costs or obligations to perform reclamation and mine closure activities could be materially different than initially estimated. At least annually, we review our reclamation liability and make adjustments for permit changes, cost revisions, changes to mining plans and the timing of expenditures. See Note 9.

Income Taxes

As a partnership, we are not a taxable entity for federal or state income tax purposes; the tax effect of our activities passes through to our unitholders. Therefore, no provision or liability for federal or state income taxes is included in our financial statements. Net income (loss) for financial statement purposes may differ significantly from taxable income (loss) reportable to our unitholders as a result of timing or permanent differences between financial reporting under US GAAP and the regulations promulgated by the Internal Revenue Service.

Revenue Recognition

Revenue from coal sales is recognized and recorded when shipment or delivery to the customer has occurred, prices are fixed or determinable, and the title or risk of loss has passed. Coal sales prices are subject to premiums and reductions based on variations in coal quality delivered versus specifications in our coal supply contracts, but such adjustments are typically confirmed in a matter of days. Risk of loss typically transfers to the customer at the mine or dock, when the coal is loaded on the rail, barge, or truck.

Other revenue consists primarily of clay and limestone sales, royalty income, service fees, and other miscellaneous revenue. Clay and limestone sales relate to material we recover during the coal mining process and sell to third parties. Royalty income relates to underground coal reserves that we sublease to a third party mining company. For the years ended 2013, 2012 and 2011, we received royalties of $8, $1,496 and $3,202, respectively. In 2012, we received an advance payment of $2.2 million for these royalties in exchange for a significant reduction in the amount of the overriding royalty going forward. Service fees are earned for operating a coal unloading facility, providing river barge loading services, and hauling ash. Periodically, we recognize miscellaneous revenue related to lost coal claims that result from granting third-party right-of-way access through small portions of various mine complexes.

Below-Market Coal Sales Contracts

Our below-market coal sales contracts were acquired through the Phoenix Coal acquisition in 2009 and represent contracts for which the prevailing market price for the specified coal was in excess of the contract price. The fair value was based on discounted cash flows resulting from the difference between the below-market contract price and the prevailing market price at the date of acquisition. The fair value adjustments are amortized into coal sales on the basis of tons shipped over the terms of the respective contracts. Amortization of these below-market contracts included in revenue was $60, $623 and $939 for the years ended December 31, 2013, 2012 and 2011, respectively. The current portion of the net carrying value of our below-market coal sales contracts was reflected in our consolidated balance sheets as “other current liabilities.” No such amounts remained at December 31, 2013.

Equity-Based Compensation

We account for equity-based awards in accordance with applicable guidance, which establishes standards of accounting for transactions in which an entity exchanges its equity instruments for goods or services. Equity-based compensation expense is recorded based upon the fair value of the award at grant date. The fair value of our LTIP units is determined based on the closing sales price of our units on the New York Stock Exchange on the grant date. The related expense is recognized on a straight-line basis over the corresponding vesting period. See Note 12.

Noncontrolling Interest

US GAAP requires noncontrolling interests to be reported as a separate component of equity. The amount of net income attributable to the noncontrolling interests is recorded in “net income attributable to noncontrolling interest” in our consolidated statements of operations. See Note 14.

Earnings (Losses) Per Unit

For purposes of our earnings per unit calculation, we apply the two class method. All outstanding limited partner units and general partner units share pro rata in income (loss) allocations and distributions, but only our general partner has voting rights. Limited partner units are further segregated into common units and subordinated units.

Limited Partner Units: Basic earnings (losses) per unit are computed by dividing net income (loss) attributable to limited partners by the weighted average units outstanding, including unexercised participating warrants, during the reporting period. Diluted earnings (losses) per unit are computed similar to basic earnings (losses) per unit except that the weighted average units outstanding and net income (loss) attributable to limited partners are increased to include phantom units that have not yet vested and that will convert to limited partnership units upon vesting. In periods of a loss, the phantom units are anti-dilutive and therefore not included in the earnings (losses) per unit calculation.

General Partner Units: Basic earnings (losses) per unit are computed by dividing net income (loss) attributable to our GP by the weighted average units outstanding, including unexercised participating warrants, during the reporting period. Diluted earnings (losses) per unit for our GP are computed similar to basic earnings (losses) per unit except that the net income (loss) attributable to the general partner units is adjusted for the dilutive impact of the phantom units. In periods of a loss, the phantom units are anti-dilutive and therefore not included in the earnings (losses) per unit calculation.

New Accounting Standards Issued

There were various updates recently issued, most of which represented technical corrections to the accounting literature or application to specific industries. We do not believe that the adoption of the guidance provided by these updates will have a material impact on our consolidated financial statements.

Reclassifications

Certain prior-year amounts have been reclassified in our consolidated balance sheet as of December 31, 2012. Payments due on the term note of $6 million have been reclassified from “long-term debt” to “current portion of long-term debt.”

Certain prior-year amounts have been reclassified in our consolidated statements of cash flows to conform with current-year classifications. These reclassifications are to reclassify “change in restricted cash” in “Cash Flows From Investing Activities” to “restricted cash” in “Cash Flows From Operating Activities.” 

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Note 4 - Inventory (Tables)

12 Months Ended

Dec. 31, 2013

Inventory Disclosure [Abstract]

Schedule of Inventory, Current [Table Text Block]

	As of December 31,
	2013		2012
Coal	$	5,957	$	5,609
Fuel		1,879		1,893
Spare parts and supplies		6,004		5,052
Total	$	13,840	$	12,554

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Note 20 - Supplemental Cash Flow Information (Details) - Supplemental Cash Flow Information (USD $) In Thousands, unless otherwise specified	12 Months Ended
	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
Cash paid for:
Interest	$ 12,258	$ 10,739	$ 6,976
Non-cash activities:
Coal reserves acquired with debt		307
Property and equipment acquired with debt	1,000
Reclamation and mine closure costs capitalized in mine development	8,927	16,011	12,278
Value of debt assigned to warrants	7,879
Market value of common units vested in LTIP	$ 330	$ 849	$ 2,055

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Note 12 - Long-Term Incentive Plan (Tables)

12 Months Ended

Dec. 31, 2013

Disclosure of Compensation Related Costs, Share-based Payments [Abstract]

Schedule of Share-based Compensation, Restricted Stock Units Award Activity [Table Text Block]

	Units			Weighted Average Grant Date Fair Value
Unvested balance at December 31, 2011		80,043		$	16.25
Granted		312,138			10.08
Issued		(71,066	)		9.68
Surrendered		(63,152	)		11.82
Unvested balance at December 31, 2012		257,963			11.67
Granted		438,990			3.98
Issued		(115,883	)		5.74
Surrendered		(21,886	)		13.59
Unvested balance at December 31, 2013		559,184			6.79

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Note 5 - Property, Plant and Equipment, Net (Details) (USD $) In Millions, unless otherwise specified	1 Months Ended		12 Months Ended
	Jun. 30, 2013	Apr. 30, 2012	Dec. 31, 2013
Property, Plant and Equipment [Abstract]
Gain (Loss) on Disposition of Assets	$ 6.1	$ 6.3
Royalty Rights, Percentage of Net Revenue			20.00%

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Note 12 - Long-Term Incentive Plan (Details) - Unvested LTIP Units (Restricted Stock Units (RSUs) [Member], USD $)	12 Months Ended
	Dec. 31, 2013	Dec. 31, 2012
Restricted Stock Units (RSUs) [Member]
Note 12 - Long-Term Incentive Plan (Details) - Unvested LTIP Units [Line Items]
Balance	257,963,000	80,043,000
Balance (in Dollars per share)	$ 11.67	$ 16.25
Granted	438,990,000	312,138,000
Granted (in Dollars per share)	$ 3.98	$ 10.08
Issued	(115,883,000)	(71,066,000)
Issued (in Dollars per share)	$ 5.74	$ 9.68
Surrendered	(21,886,000)	(63,152,000)
Surrendered (in Dollars per share)	$ 13.59	$ 11.82
Balance	559,184,000	257,963,000
Balance (in Dollars per share)	$ 6.79	$ 11.67

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Consolidated Balance Sheets (USD $) In Thousands, unless otherwise specified	Dec. 31, 2013	Dec. 31, 2012
CURRENT ASSETS:
Cash	$ 3,089	$ 3,977
Accounts receivable	25,850	19,792
Inventory	13,840	12,554
Advance royalties	2,604	4,461
Prepaid expenses and other assets	1,737	2,046
Assets held for sale		6,106
Total current assets	47,120	48,936
PROPERTY, PLANT AND EQUIPMENT, NET	144,426	158,483
ADVANCE ROYALTIES, LESS CURRENT PORTION	8,800	4,861
INTANGIBLE ASSETS, NET	1,188	1,442
OTHER LONG-TERM ASSETS	22,821	7,177
Total assets	224,355	220,899
CURRENT LIABILITIES:
Accounts payable	23,932	26,893
Current portion of long-term debt	7,901	102,970
Current portion of reclamation and mine closure costs	5,996	3,869
Accrued taxes other than income taxes	1,293	1,213
Accrued payroll and related expenses	3,389	1,629
Other liabilities	3,457	2,491
Total current liabilities	45,968	139,065
LONG-TERM DEBT	155,375	41,557
RECLAMATION AND MINE CLOSURE COSTS	25,658	25,144
WARRANTS	4,599
OTHER LONG-TERM LIABILITIES	3,753	3,806
Total liabilities	235,353	209,572
PARTNERS’ (DEFICIT) CAPITAL:
Limited partners (20,867,073 and 20,751,190 units outstanding as of December 31, 2013 and 2012, respectively)	(13,460)	9,593
General partner (423,494 units outstanding as of December 31, 2013 and 2012)	(2,507)	(2,010)
Total Oxford Resource Partners, LP (deficit) capital	(15,967)	7,583
Noncontrolling interest	4,969	3,744
Total partners’ (deficit) capital	(10,998)	11,327
Total liabilities and partners’ (deficit) capital	$ 224,355	$ 220,899

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Note 22 - Supplemental Quarter Financial Information (Unaudited) (Tables)

12 Months Ended

Dec. 31, 2013

Quarterly Financial Information Disclosure [Abstract]

Schedule of Quarterly Financial Information [Table Text Block]

	2013
	March 31			June 30			September 30			December 31			Total
Total revenues	$	88,726		$	88,125		$	87,586		$	82,330		$	346,767
Net (loss) income from operations		(3,356	)		2,434			(1,036	)		(3,972	)		(5,930	)
Net loss attributable to Oxford Resource
Partners, LP unitholders		(6,547	)		(4,510	)		(5,599	)		(8,269	)		(24,925	)
Net loss allocated to general partner		(131	)		(89	)		(112	)		(165	)		(497	)
Net loss allocated to limited partners		(6,416	)		(4,421	)		(5,487	)		(8,104	)		(24,428	)
Loss per limited partner unit:
Basic	$	(0.31	)	$	(0.21	)	$	(0.22	)	$	(0.33	)	$	(1.07	)
Diluted	$	(0.31	)	$	(0.21	)	$	(0.22	)	$	(0.33	)	$	(1.07	)
Distributions paid per unit:
Limited partners:
Common	$	-		$	-		$	-		$	-		$	-
Subordinated	$	-		$	-		$	-		$	-		$	-
General partner	$	-		$	-		$	-		$	-		$	-

	2012
	March 31			June 30			September 30			December 31			Total
Total revenues	$	97,867		$	91,948		$	97,214		$	86,498		$	373,527
Net (loss) income from operations		(12,968	)		1,338			(29	)		(2,904	)		(14,563	)
Net loss attributable to Oxford Resource
Partners, LP unitholders		(15,776	)		(1,455	)		(3,314	)		(6,263	)		(26,808	)
Net loss allocated to general partner		(315	)		(29	)		(66	)		(125	)		(535	)
Net loss allocated to limited partners		(15,461	)		(1,426	)		(3,248	)		(6,138	)		(26,273	)
Loss per limited partner unit:
Basic	$	(0.75	)	$	(0.07	)	$	(0.16	)	$	(0.29	)	$	(1.27	)
Diluted	$	(0.75	)	$	(0.07	)	$	(0.16	)	$	(0.29	)	$	(1.27	)
Distributions paid per unit:
Limited partners:
Common	$	0.4375		$	0.4375		$	0.4375		$	0.2000		$	1.5125
Subordinated	$	0.4375		$	0.1000		$	0.1000		$	-		$	0.6375
General partner	$	0.4375		$	0.2688		$	0.2688		$	0.1000		$	1.0750

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Consolidated Statements of Cash Flows (USD $) In Thousands, unless otherwise specified	12 Months Ended
	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
CASH FLOWS FROM OPERATING ACTIVITIES:
Net loss	$ (23,700)	$ (26,053)	$ (8,329)
Adjustments to reconcile net loss to net cash from operating activities:
Depreciation, depletion and amortization	48,081	51,170	51,905
Impairment and restructuring expenses	1,761	15,650
Change in fair value of warrants	(3,280)	0
Interest rate swap and fuel contract adjustments to market	(12)	(144)	48
Non-cash interest expense	4,094
Amortization and write-off of deferred financing costs	3,986	2,175	1,600
Non-cash equity-based compensation expense	1,441	1,262	1,077
Non-cash changes in mine reclamation obligations	2,293	1,567	1,503
Amortization of below-market coal sales contracts	(60)	(623)	(939)
(Gain) loss on disposal of assets, net	(6,488)	(8,021)	1,352
Changes in assets and liabilities:
Accounts receivable	(6,058)	8,596	(280)
Inventory	(778)	(554)	1,731
Advance royalties	(2,320)	(123)	(740)
Restricted cash	(40)	1,811	(2,179)
Other assets	147	(1,224)	(452)
Accounts payable	(2,962)	1	866
Reclamation and mine closure costs	(8,222)	(8,966)	(5,491)
Accrued taxes other than income taxes	80	(519)	89
Accrued payroll and related expenses	1,760	(905)	(90)
Other liabilities	(47)	(1,513)	(383)
Net cash from operating activities	9,676	33,587	41,288
CASH FLOWS FROM INVESTING ACTIVITIES:
Purchase of property and equipment	(17,773)	(19,122)	(33,859)
Purchase of coal reserves and land	(1,532)	(125)	(1,088)
Mine development costs	(3,027)	(3,440)	(5,196)
Proceeds from sale of assets	6,424	12,417	849
Insurance proceeds	3,035	400	1,096
Net cash from investing activities	(12,873)	(9,870)	(38,198)
CASH FLOWS FROM FINANCING ACTIVITIES:
Proceeds from borrowings	150,000
Payments on borrowings	(56,072)	(10,921)	(6,231)
Advances on line of credit	53,588	51,000	62,000
Payments on line of credit	(126,088)	(39,000)	(15,000)
Debt issuance costs	(9,569)	(1,086)
Collateral for reclamation bonds	(9,550)
Capital contributions from partners		12	28
Distributions to partners		(22,777)	(36,843)
Distributions to noncontrolling interest			(4,901)
Net cash from financing activities	2,309	(22,772)	(947)
NET CHANGE IN CASH	(888)	945	2,143
CASH, beginning of the year	3,977	3,032	889
CASH, end of the year	$ 3,089	$ 3,977	$ 3,032

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Note 7 - Intangible Assets (Details) - Intangible Assets (Customer Relationships [Member], USD $) In Thousands, unless otherwise specified	12 Months Ended
	Dec. 31, 2013	Dec. 31, 2012
Customer Relationships [Member]
Intangible assets
Estimated Remaining Life	13 years	14 years
Cost	$ 3,315	$ 3,315
Accumulated Amortization	2,127	1,873
Net Carrying Value	$ 1,188	$ 1,442

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Note 7 - Intangible Assets (Tables)

12 Months Ended

Dec. 31, 2013

Disclosure Text Block [Abstract]

Schedule of Finite-Lived Intangible Assets [Table Text Block]

	As of December 31, 2013
	Estimated Remaining Life (years)		Cost		Accumulated Amortization		Net Carrying Value
Intangible assets
Customer relationships		13	$	3,315	$	2,127	$	1,188

	As of December 31, 2012
	Estimated Remaining Life (years)		Cost		Accumulated Amortization		Net Carrying Value
Intangible assets
Customer relationships		14	$	3,315	$	1,873	$	1,442

Schedule of Finite-Lived Intangible Assets, Future Amortization Expense [Table Text Block]

For the years ending December 31, 2014	$	227
2015		204
2016		183
2017		126
2018		84
Thereafter		364

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Note 10 - Long-Term Debt (Details) (USD $)	1 Months Ended	12 Months Ended						1 Months Ended			12 Months Ended								1 Months Ended			12 Months Ended		1 Months Ended		12 Months Ended					12 Months Ended												12 Months Ended		1 Months Ended							12 Months Ended		1 Months Ended	12 Months Ended
	Aug. 31, 2010	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011	Jun. 30, 2013	Jun. 24, 2013	Dec. 31, 2013 Net of Debt Discount [Member] Second Lien Term Loan [Member]	Apr. 30, 2013 Notes Payable, Other Payables [Member] AEP Conesville Coal Preparation Plant [Member]	Dec. 31, 2013 Common Units [Member]	Dec. 31, 2013 Subordinated Units [Member]	Dec. 31, 2013 Selling, General and Administrative Expenses [Member] Previous Credit Facility [Member]	Dec. 31, 2013 Selling, General and Administrative Expenses [Member]	Dec. 31, 2013 Interest Rate Floor [Member] London Interbank Offered Rate (LIBOR) [Member] Second Lien Debt [Member]	Dec. 31, 2013 Interest Rate Floor [Member] London Interbank Offered Rate (LIBOR) [Member] First Lien Debt [Member]	Dec. 31, 2013 Interest Rate Floor [Member] Reference Rate [Member] First Lien Debt [Member]	Dec. 31, 2013 Interest Rate Floor [Member] Second Lien Debt [Member]	Dec. 31, 2013 Spread on Variable Rate [Member] London Interbank Offered Rate (LIBOR) [Member] Revolving Credit Facility [Member]	Dec. 31, 2013 Spread on Variable Rate [Member] Reference Rate [Member] Revolving Credit Facility [Member]	Aug. 31, 2010 Installment 1 [Member] CONSOL Coal Reserve Note Payable [Member]	Aug. 31, 2010 Installment 2 [Member] CONSOL Coal Reserve Note Payable [Member]	Aug. 31, 2010 Installment 3 [Member] CONSOL Coal Reserve Note Payable [Member]	Dec. 31, 2013 Quarterly [Member] First Lien Term Loan [Member]	Dec. 31, 2013 Quarterly [Member] Second Lien Term Loan [Member]	Sep. 30, 2010 Quarterly [Member]	Apr. 30, 2013 AEP Conesville Coal Preparation Plant [Member]	Dec. 31, 2013 London Interbank Offered Rate (LIBOR) [Member] First Lien Debt [Member]	Dec. 31, 2013 London Interbank Offered Rate (LIBOR) [Member] Second Lien Debt [Member]	Dec. 31, 2013 London Interbank Offered Rate (LIBOR) [Member] Revolving Credit Facility [Member]	Dec. 31, 2013 London Interbank Offered Rate (LIBOR) [Member] First Lien Term Loan [Member]	Dec. 31, 2013 London Interbank Offered Rate (LIBOR) [Member] Second Lien Term Loan [Member]	Dec. 31, 2013 Reference Rate [Member] First Lien Debt [Member]	Dec. 31, 2013 Reference Rate [Member] Second Lien Debt [Member]	Dec. 31, 2013 Reference Rate [Member] Revolving Credit Facility [Member]	Dec. 31, 2013 Spread on Variable Rate [Member] First Lien Term Loan [Member]	Dec. 31, 2013 Spread on Variable Rate [Member] Second Lien Term Loan [Member]	Dec. 31, 2013 PIK Interest [Member] Second Lien Term Loan [Member]	Dec. 31, 2013 First Lien Debt [Member] Revolving Credit Facility [Member]	Dec. 31, 2012 First Lien Debt [Member] Revolving Credit Facility [Member]	Dec. 31, 2013 First Lien Debt [Member] Term Loan [Member]	Dec. 31, 2012 First Lien Debt [Member] Term Loan [Member]	Dec. 31, 2013 Second Lien Debt [Member] Term Loan [Member]	Dec. 31, 2012 Second Lien Debt [Member] Term Loan [Member]	Dec. 31, 2013 Second Lien Debt [Member]	Dec. 31, 2013 Collateral For Reclamation Bonds [Member] First Lien Debt [Member]	Aug. 31, 2010 CONSOL Coal Reserve Note Payable [Member]	Dec. 31, 2013 CONSOL Coal Reserve Note Payable [Member]	Dec. 31, 2012 CONSOL Coal Reserve Note Payable [Member]	Dec. 31, 2013 Revolving Credit Facility [Member]	Jun. 30, 2013 Revolving Credit Facility [Member]	Jul. 31, 2010 Revolving Credit Facility [Member]	Jul. 31, 2010 Term Loan [Member]	Dec. 31, 2013 First Lien Term Loan [Member]	Jun. 30, 2013 First Lien Term Loan [Member]	Jun. 30, 2013 Second Lien Term Loan [Member]	Dec. 31, 2013 Second Lien Term Loan [Member]
Note 10 - Long-Term Debt (Details) [Line Items]
Line of Credit Facility, Maximum Borrowing Capacity					$ 175,000,000																																												$ 25,000,000	$ 115,000,000	$ 60,000,000		$ 75,000,000	$ 75,000,000	$ 75,000,000
Line of Credit Facility, Periodic Payment																						1,300,000	200,000	1,500,000
Line of Credit Facility Option for Additional Term Loan																																																						10,000,000
Line of Credit Facility, Interest Rate at Period End		9.53%															6.75%	6.25%										1.50%	1.50%	1.25%			3.25%	6.75%	9.75%	5.75%												8.76%				8.25%			11.00%
Class of Warrant or Right, Number of Securities Called by Warrants or Rights (in Shares)									1,955,666	1,814,185
Class of Warrant or Right, Exercise Price of Warrants or Rights (in Dollars per Item)		0.01
Warrants and Rights Outstanding		4,599,000				7,900,000
Liability Related to Warrants Increase (Decrease)		3,300,000
Line of Credit Facility, Amount Outstanding							67,100,000																														19,500,000	92,000,000	69,321,000	45,000,000	70,862,000	0		9,600,000				19,500,000				69,300,000			70,900,000
Reference Rate													1.25%	1.50%	3.00%	3.00%
Debt Instrument, Basis Spread on Variable Rate																										6.75%	9.75%				6.25%	11.75%
Line of Credit Facility, Remaining Borrowing Capacity		5,100,000																																														5,100,000
Repayments of Lines of Credit																																																				5,700,000
Amortization of Debt Discount (Premium)																																											1,500,000
Paid-in-Kind Interest																																																							2,300,000
Debt Instrument, Unamortized Discount																																																							6,400,000
Payment For Coal Reserve	850,000	5,000
Debt Instrument, Face Amount																																													13,458,000
Debt Instrument, Term																																													3 years
Debt Instrument, Periodic Payment																			5,383,000	5,383,000	2,692,000				500,000
Receivable with Imputed Interest, Effective Yield (Interest Rate)		6.75%																																											5.50%
Long-term Debt		163,276,000	144,527,000																																											2,584,000	7,508,000
Payments to Acquire Businesses, Gross																									488,000
Business Combination, Consideration Transferred, Other								1,000,000
Unamortized Debt Issuance Expense		800,000
Debt Issuance Cost		9,600,000
Amortization of Financing Costs		3,986,000	2,175,000	1,600,000
Refinancing Related Fees											$ 2,400,000	$ 700,000

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Note 16 - Retirement Plan

12 Months Ended

Dec. 31, 2013

Compensation and Retirement Disclosure [Abstract]

Pension and Other Postretirement Benefits Disclosure [Text Block]

NOTE 16: RETIREMENT PLAN

We maintain a 401(k) plan for the benefit of our employees. For the years ended December 31, 2012 and 2011, we committed to and made an employer contribution at 4% of qualified wages totaling $1.9 million and $2.2 million, respectively. For the year ended December 31, 2013, we did not commit to make and are not making any discretionary employer contribution to the 401(k) plan.

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Note 8 - Other Long-term Assets and Other Current Liabilities (Tables)

12 Months Ended

Dec. 31, 2013

Other Longterm Assets And Other Current Liabilities [Abstract]

Schedule of Other Assets [Table Text Block]

	As of December 31,
	2013		2012
Reclamation bond collateral(1)	$	9,582	$	-
Deferred financing costs, net(1)		7,644		2,061
Restricted cash		3,969		3,929
Deposits		1,526		1,070
Other		100		117
Total	$	22,821	$	7,177

Other Current Liabilities [Table Text Block]

	As of December 31,
	2013		2012
Accrued interest and interest rate swap(2)	$	1,424	$	709
Accrued royalties		1,062		815
Other		971		967
Total	$	3,457	$	2,491

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Note 18 - Concentration of Credit Risk and Major Customers

12 Months Ended

Dec. 31, 2013

Risks and Uncertainties [Abstract]

Concentration Risk Disclosure [Text Block]

NOTE 18: CONCENTRATION OF CREDIT RISK AND MAJOR CUSTOMERS

We have a credit policy that establishes procedures to determine creditworthiness and credit limits for customers. Generally, credit is extended based on an evaluation of the customer’s financial condition. Collateral is not generally required, unless credit cannot be established.

We market our coal principally to electric utilities, electric cooperatives, municipalities and industrial customers in Indiana, Kentucky, Michigan, Ohio, Pennsylvania and West Virginia. As of December 31, 2013 and 2012, accounts receivable from electric utilities totaled $19.6 million and $12.6 million, respectively, or 75.9% and 63.6% of total receivables, respectively. The following table shows the amount of sales to each customer (in each year where applicable, a “Major Customer”) which individually accounted for greater than 10% of sales in any of the years ended December 31, 2013, 2012 and 2011, with a portion of these sales being facilited by coal brokers.

	Revenues for the Year Ended December 31,
Customer	2013		2012		2011
	(in millions)
American Electric Power	$	146.3	$	128.8	$	139.7
First Energy		69.2		85.8		58.0
East Kentucky Power Cooperative		41.4		56.6		43.7
Big Rivers Electric		*		*		44.0

*Sales to this customer were less than 10% in the respective year.

Three Major Customers in 2013 and 2012, in the aggregate, represented 74.1% and 72.6%, respectively, of our total sales in the applicable year, and four Major Customers in 2011, in the aggregate, represented 71.3% of our total sales in that year. Three of the Major Customers in each of 2013 and 2012, in the aggregate, represented 81.5% and 67.9% of the outstanding accounts receivable at December 31, 2013 and 2012, respectively.

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Note 11 - Fair Value of Financial Instruments (Details) (Warrant [Member], USD $)	12 Months Ended
	Dec. 31, 2013
Warrant [Member]
Note 11 - Fair Value of Financial Instruments (Details) [Line Items]
Warrants, Fair Value Per Unit (in Dollars per Item)	1.22
Fair Value Assumption, Spot Price Per Unit (in Dollars per Item)	1.23
Fair Value Assumption Exercise Price (in Dollars per share)	$ 0.01
Fair Value Assumptions, Expected Term	4 years 6 months
Fair Value Assumptions, Expected Volatility Rate	80.00%
Fair Value Assumptions, Risk Free Interest Rate	1.75%

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Note 1 - Organization and Presentation

12 Months Ended

Dec. 31, 2013

Disclosure Text Block [Abstract]

Organization, Consolidation and Presentation of Financial Statements Disclosure [Text Block]

NOTE 1:   ORGANIZATION AND PRESENTATION

Basis of Presentation and Principles of Consolidation

The accompanying consolidated financial statements include the accounts and operations of the Partnership and its consolidated subsidiaries and are prepared in conformity with accounting principles generally accepted in the United States of America (“US GAAP”).

Significant Relationships Referenced in Notes to Consolidated Financial Statements

● “We,”“us,” “our,” or the “Partnership” means the business and operations of Oxford Resource Partners, LP, the parent entity, as well as its consolidated subsidiaries.

● Our “GP” means Oxford Resources GP, LLC, the general partner of Oxford Resource Partners, LP.

Organization

We are a low-cost producer of high-value thermal coal and 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. These coal reserves are mined by our subsidiaries, Oxford Mining Company, LLC (“Oxford Mining”), Oxford Mining Company - Kentucky, LLC and Harrison Resources, LLC (“Harrison Resources”).

We are managed by our GP and all executives, officers and employees who provide services to us are employees of our GP. Charles C. Ungurean, the President and Chief Executive Officer of our GP and a member of our GP’s board of directors (“Mr. C. Ungurean”), and Thomas T. Ungurean, a former officer of our GP (“Mr. T. Ungurean”), are the co-owners of one of our limited partners, C&T Coal, Inc. (“C&T”).

AIM Oxford Holdings, LLC (“AIM Oxford”) and C&T held 65.81% and 33.49%, respectively, of the ownership interests in our GP with the remaining ownership interests therein being a 0.47% ownership interest held by Daniel M. Maher, our Senior Vice President, Chief Legal Officer and Secretary, and a 0.23% ownership interest held by Jeffrey M. Gutman, a former officer of our GP. As of December 31, 2013, AIM Oxford, C&T and our GP had ownership in the Partnership of 35.33%, 17.98% and 1.99%, respectively. The remaining 44.70% was held by the general public and participants in our Long-Term Incentive Plan (our “LTIP”).

We have a 51% ownership interest in Harrison Resources and also have control for purposes of US GAAP. As a result, we consolidate all of Harrison Resources’ accounts with all material intercompany transactions and balances being eliminated in our consolidated financial statements. The remaining 49% ownership interest in Harrison Resources that we do not own is reflected as “noncontrolling interest” in our consolidated balance sheets and statements of operations. See Note 14.

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Consolidated Balance Sheets (Parentheticals)	Dec. 31, 2013	Dec. 31, 2012
Limited partner capital account, units outstanding	20,867,073	20,751,190
General partner capital account, units outstanding	423,494	423,494

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Note 11 - Fair Value of Financial Instruments

12 Months Ended

Dec. 31, 2013

Fair Value Disclosures [Abstract]

Fair Value Disclosures [Text Block]

NOTE 11: FAIR VALUE OF FINANCIAL INSTRUMENTS

We utilize fair value measurement guidance that, among other things, defines fair value, requires enhanced disclosures about assets and liabilities carried at fair value and establishes a hierarchical disclosure framework based upon the quality of inputs used to measure fair value. We have elected not to measure any additional financial assets or liabilities at fair value, other than those required to be recorded at fair value.

The financial instruments measured at fair value on a recurring basis are summarized below:

	Fair Value Measurements as of December 31, 2013
	Quoted Prices in Active Markets for Identical Liabilities		Significant Other Observable Inputs			Significant Unobservable Inputs
Description	(Level 1)		(Level 2)			(Level 3)
Warrants	$	-	$	(4,599	)	$	-

	Fair Value Measurements as of December 31, 2012
	Quoted Prices in Active Markets for Identical Liabilities		Significant Other Observable Inputs			Significant Unobservable Inputs
Description	(Level 1)		(Level 2)			(Level 3)
Interest rate swap agreement	$	-	$	(12	)	$	-

The interest rate swap agreement matured in the first quarter of 2013.

The warrants are fair valued at each balance sheet date using the Black-Scholes model. At December 31, 2013, the fair value of each warrant was $1.22, based on the following assumptions: spot price of $1.23 per unit, exercise price of $0.01 per unit, term of 4.5 years, volatility of 80% and a five-year treasury rate of 1.75%.

The following methods and assumptions were used to estimate the fair values of financial instruments for which the fair value option was not elected:

Cash and restricted cash, accounts receivable and accounts payable:  The carrying amount reported in the consolidated balance sheets for cash and restricted cash, accounts receivable and accounts payable approximates fair value due to the short maturity of these instruments.

Derivatives: The fair value of derivatives is established using a discounted cash flow analysis using primarily inputs that can be observed within financial markets, such as LIBOR rates.

Fixed rate debt:  The fair value of fixed rate debt is estimated using discounted cash flow analyses, based on current market rates for instruments with similar cash flows. As such, the fair value of fixed rate debt is considered level 2.

Variable rate debt:  The fair value of variable rate debt is estimated using discounted cash flow analyses, based on our best estimates of market rate for instruments with similar cash flows. As such, the fair value of variable rate debt is considered level 2.

The carrying amounts and fair values of financial instruments for which the fair value option was not elected are as follows:

	As of December 31, 2013				As of December 31, 2012
	Carrying Amount		Fair Value		Carrying Amount		Fair Value
Fixed rate debt	$	3,593	$	3,386	$	7,527	$	7,642
Variable rate debt		159,683		159,683		137,000		137,000

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Document And Entity Information (USD $)	12 Months Ended
	Dec. 31, 2013	Jun. 30, 2013	Feb. 28, 2014 Subordinated Units [Member]	Feb. 28, 2014 Common Stock [Member]
Document Information [Line Items]
Entity Registrant Name	Oxford Resource Partners LP
Document Type	10-K
Current Fiscal Year End Date	--12-31
Entity Common Stock, Shares Outstanding			10,280,380	10,589,149
Entity Public Float		$ 24,791,000
Amendment Flag	false
Entity Central Index Key	0001412347
Entity Current Reporting Status	Yes
Entity Voluntary Filers	No
Entity Filer Category	Non-accelerated Filer
Entity Well-known Seasoned Issuer	No
Document Period End Date	Dec. 31, 2013
Document Fiscal Year Focus	2013
Document Fiscal Period Focus	FY

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Note 12 - Long-Term Incentive Plan

12 Months Ended

Dec. 31, 2013

Disclosure of Compensation Related Costs, Share-based Payments [Abstract]

Disclosure of Compensation Related Costs, Share-based Payments [Text Block]

NOTE 12: LONG-TERM INCENTIVE PLAN

Under our LTIP, we recognize equity-based compensation expense over the vesting period of the units. These units are subject to conditions and restrictions as determined by our Compensation Committee, including continued employment or service. Historically, these units generally vested in equal annual increments over four years with accelerated vesting of the first increment in certain cases. Beginning in 2012, some of the units granted to executive officers vest based on specified performance criteria.

For the years ended December 31, 2013, 2012 and 2011, we recognized equity-based compensation expense of $1,441, $1,262 and $1,077, respectively. These amounts are included in selling, general and administrative expenses. As of December 31, 2013 and 2012, $2,150 and $1,843, respectively, of cost remained unamortized. We expect to recognize these costs using the straight-line method over a remaining weighted average period of 1.2 years as of December 31, 2013.

The following table summarizes additional information concerning our unvested LTIP units:

	Units			Weighted Average Grant Date Fair Value
Unvested balance at December 31, 2011		80,043		$	16.25
Granted		312,138			10.08
Issued		(71,066	)		9.68
Surrendered		(63,152	)		11.82
Unvested balance at December 31, 2012		257,963			11.67
Granted		438,990			3.98
Issued		(115,883	)		5.74
Surrendered		(21,886	)		13.59
Unvested balance at December 31, 2013		559,184			6.79

The value of LTIP units vested during the years ended December 31, 2013, 2012 and 2011 was $963, $944 and $908, respectively.

As of December 31, 2013, 2,056,075 units were authorized for issuance under our LTIP and 1,064,001 units remained available to be awarded.  In early 2014, an additional 750,000 units were authorized and 1,347,502 units were awarded.  Subsequent to these events, 468,148 units remained available to be awarded, assuming that all grants outstanding are settled with units without reduction for income tax withholding and that no future forfeitures occur.

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Note 18 - Concentration of Credit Risk and Major Customers (Details) (USD $) In Millions, unless otherwise specified			12 Months Ended
	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2013 Three Major Customers [Member] Sales Revenue, Net [Member]	Dec. 31, 2012 Three Major Customers [Member] Sales Revenue, Net [Member]	Dec. 31, 2013 Three Major Customers [Member] Accounts Receivable [Member]	Dec. 31, 2012 Three Major Customers [Member] Accounts Receivable [Member]	Dec. 31, 2011 Four Major Customers [Member] Sales Revenue, Net [Member]	Dec. 31, 2013 Accounts Receivable from Electric Utilities [Member]	Dec. 31, 2012 Accounts Receivable from Electric Utilities [Member]
Note 18 - Concentration of Credit Risk and Major Customers (Details) [Line Items]
Fair Value, Concentration of Risk, Accounts Receivable (in Dollars)	$ 19.6	$ 12.6
Concentration Risk, Percentage			74.10%	72.60%	81.50%	67.90%	71.30%	75.90%	63.60%

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Consolidated Statements of Operations (USD $) In Thousands, except Share data, unless otherwise specified	12 Months Ended
	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
REVENUES:
Coal sales	$ 336,201	$ 364,928	$ 391,046
Other revenue	10,566	8,599	9,331
Total revenues	346,767	373,527	400,377
COSTS AND EXPENSES:
Produced coal	268,130	288,782	316,574
Purchased coal	22,297	23,685	13,480
Total cost of coal sales (excluding depreciation, depletion and amortization)	290,427	312,467	330,054
Cost of other revenue	1,619	1,195	1,799
Depreciation, depletion and amortization	48,081	51,170	51,905
Selling, general and administrative expenses	17,297	15,629	13,739
Impairment and restructuring expenses	1,761	15,650
(Gain) loss on disposal of assets, net	(6,488)	(8,021)	1,352
Total costs and expenses	352,697	388,090	398,849
(LOSS) INCOME FROM OPERATIONS	(5,930)	(14,563)	1,528
INTEREST AND OTHER EXPENSES:
Interest income	4	10	13
Interest expense	(21,054)	(11,500)	(9,870)
Change in fair value of warrants	3,280	0
Total interest and other expenses	(17,770)	(11,490)	(9,857)
NET LOSS	(23,700)	(26,053)	(8,329)
Net income attributable to noncontrolling interest	(1,225)	(755)	(4,748)
Net loss attributable to Oxford Resource Partners, LP unitholders	(24,925)	(26,808)	(13,077)
Net loss allocated to general partner	(497)	(535)	(261)
Net loss allocated to limited partners	$ (24,428)	$ (26,273)	$ (12,816)
Net loss per limited partner unit:
Basic (in Dollars per share)	$ (1.07)	$ (1.27)	$ (0.62)
Diluted (in Dollars per share)	$ (1.07)	$ (1.27)	$ (0.62)
Weighted average number of limited partner units outstanding:
Basic (in Shares)	22,776,481	20,711,952	20,641,127
Diluted (in Shares)	22,776,481	20,711,952	20,641,127
Distributions paid per unit:
General partner (in Dollars per share)	$ 0	$ 1.0750	$ 1.7500
Common Units [Member]
Distributions paid per unit:
Distributions paid per unit, limited partners (in Dollars per share)	$ 0	$ 1.5125	$ 1.7500
Subordinated Units [Member]
Distributions paid per unit:
Distributions paid per unit, limited partners (in Dollars per share)	$ 0	$ 0.6375	$ 1.7500

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Note 6 - Operating Leases

12 Months Ended

Dec. 31, 2013

Operating Leases [Abstract]

Operating Leases [Text Block]

NOTE 6: OPERATING LEASES

We lease certain operating facilities and equipment under non-cancelable lease agreements that expire on various dates through 2018. Generally, the lease terms range from three to ten years. As of December 31, 2013, aggregate lease payments under operating leases that have initial or remaining non-cancelable lease terms in excess of one year are set forth below:

For the years ending December 31,   2014	$	7,928
2015		5,947
2016		2,642
2017		651
2018		2

For the years ended December 31, 2013, 2012 and 2011, we incurred lease expenses of $8,591, $7,118 and $3,383, respectively.

We also entered into various coal reserve lease agreements under which advance royalty payments are made. Most of these advance royalty payments are recoupable against future royalty payments otherwise due based on production. Such payments are capitalized as “advance royalties” at the time of payment, and are recoupable through an offset or credit against royalties payable on future production.

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Note 5 - Property, Plant and Equipment, Net

12 Months Ended

Dec. 31, 2013

Property, Plant and Equipment [Abstract]

Property, Plant and Equipment Disclosure [Text Block]

NOTE 5: PROPERTY, PLANT AND EQUIPMENT, NET

Property, plant and equipment, net of accumulated depreciation, depletion and amortization, consisted of the following:

	As of December 31,
	2013			2012
Property, plant and equipment, gross:
Land	$	3,016		$	2,947
Coal reserves		49,574			53,376
Mine development costs		58,077			46,176
Buildings and tipple		1,957			1,957
Machinery and equipment		202,663			195,321
Vehicles		4,522			4,488
Furniture and fixtures		1,584			1,518
Railroad sidings		160			160
Total property, plant and equipment, gross		321,553			305,943
Less: accumulated depreciation, depletion and amortization		(177,127	)		(147,460	)
Total property, plant and equipment, net	$	144,426		$	158,483

The amounts of depreciation expense related to owned and leased fixed assets, depletion expense related to owned and leased coal reserves, amortization expense related to mine development costs and amortization expense related to intangible assets for the respective years are as follows:

	For the Year Ended December 31,
	2013		2012		2011
Depreciation	$	30,786	$	34,276	$	37,022
Depletion		4,513		4,869		5,697
Mine development amortization		12,528		11,783		8,913
Intangible asset amortization(1)		254		242		273
	$	48,081	$	51,170	$	51,905

(1) See Note 7.

In June 2013 and April 2012, we completed the sale of certain oil and gas rights and land in eastern Ohio for $6.1 million and $6.3 million, respectively, which is recorded in “(gain) loss on disposal of assets, net” in our consolidated statement of operations for the years ended December 31, 2013 and 2012. As part of these transactions, we retained royalty rights equivalent to 20% of net revenue once the wells are producing. We expect royalty revenue to be generated from these rights starting in the first quarter of 2014, which royalty revenue will be recorded in “other revenue.”

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Note 17 - Commitments and Contingencies

12 Months Ended

Dec. 31, 2013

Commitments and Contingencies Disclosure [Abstract]

Commitments and Contingencies Disclosure [Text Block]

NOTE 17: COMMITMENTS AND CONTINGENCIES

Coal Sales Contracts

We are committed under long-term contracts to sell coal that meets certain quality requirements at specified prices. Many of these prices are subject to cost pass-through or cost adjustment provisions that mitigate some risk from rising costs. Quantities sold under some of these contracts may vary from year to year within certain limits at the option of the customer or us. As of December 31, 2013, the remaining terms of our long-term contracts range from one to two years.

We received a contract termination notice in March 2012 from a customer of our Illinois Basin operations. This contract required us to supply the customer with 0.8 million tons of coal per year. Absent any termination thereof, the term of the contract continued until December 31, 2015. We believe that this customer's action was taken in bad faith, motivated by the combination of the price increase that had recently gone into effect and current coal market conditions. We are aggressively pursuing compensation for our damages through all appropriate legal measures.

Purchase Commitments

From time to time, we purchase coal from third parties in order to meet quality or delivery requirements under our customer contracts. We buy coal on the spot market, and the cost of that coal is dependent upon the market price and quality of the coal. We previously had a long-term purchase contract for 0.4 million tons of coal per year with a separate supplier who had asserted that the contract had terminated by its terms. We entered into a settlement agreement with the supplier in February 2013 under which the parties agreed to terminate the contract with the supplier making a one-time payment of $2.1 million to us.

Transportation

We depend upon barge, rail and truck transportation systems to deliver coal to our customers. We have a long-term rail transportation contract that has been amended and extended through March 31, 2015.

401(k) Plan

As of September 30, 2013, we satisfied the obligation to pay our GP for the purpose of funding our GP’s commitment to our 401(k) plan in the amount of $1.9 million related to plan and fiscal year ended December 31, 2012. For the year ended December 31, 2013, the GP made no commitment to fund an employer contribution to our 401(k) plan.

Surety and Performance Bonds

As of December 31, 2013, we had $37.0 million in surety bonds outstanding to secure certain reclamation obligations which were collateralized by cash of $9.6 million. Such cash collateral is included in “other long-term assets” on our consolidated balance sheet and “collateral for reclamation bonds” within financing activities on our consolidated statement of cash flows. Additionally, we had road bonds totaling $0.6 million and performance bonds totaling $2.1 million outstanding to secure contractual performance. We believe these bonds will expire without any claims or payments thereon and therefore will not have a material adverse effect on our financial position, liquidity or operations.

Legal

From time to time, we are involved in various legal proceedings arising in the ordinary course of business. While the ultimate resolution of these proceedings cannot be predicted with certainty, we believe that these claims will not have a material adverse effect on our financial position, liquidity or operations.

Guarantees

Our GP and the Partnership guarantee certain obligations of our subsidiaries. We believe that these guarantees will expire without any liability to the guarantors, and therefore will not have a material adverse effect on our financial position, liquidity or operations.

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Note 13 - Earnings (Losses) Per Unit

12 Months Ended

Dec. 31, 2013

Earnings Per Share [Abstract]

Earnings Per Share [Text Block]

NOTE 13: EARNINGS (LOSSES) PER UNIT

The computation of basic and diluted earnings (losses) per unit under the two class method for limited partner units and general partner units is presented as follows:

	For the Year Ended December 31,
	2013			2012			2011
Limited partner units
Average units outstanding:
Basic		22,776,481			20,711,952			20,641,127
Effect of equity-based compensation	N/A			N/A			N/A
Diluted		22,776,481			20,711,952			20,641,127
Net loss allocated to limited partners
Basic	$	(24,470	)	$	(26,273	)	$	(12,816	)
Diluted		(24,470	)		(26,273	)		(12,816	)
Net loss per limited partner unit
Basic	$	(1.07	)	$	(1.27	)	$	(0.62	)
Diluted		(1.07	)		(1.27	)		(0.62	)
General partner units
Average units outstanding:
Basic and diluted		423,618			422,609			421,038
Net loss allocated to general partner
Basic	$	(455	)	$	(535	)	$	(261	)
Diluted		(455	)		(535	)		(261	)
Net loss per general partner unit
Basic	$	(1.07	)	$	(1.27	)	$	(0.62	)
Diluted		(1.07	)		(1.27	)		(0.62	)
Anti-dilutive units (1) (2)		-			-			68,760
Distributions paid per unit:
Limited partners:
Common	$	-		$	1.5125		$	1.7500
Subordinated		-			0.6375			1.7500
General partner		-			1.0750			1.7500

(1) Anti-dilutive units are not used in calculating diluted average units.

(2) Unvested LTIP units are not dilutive units for the years ended December 31, 2013 and 2012.

Under the Partnership’s partnership agreement, arrearage amounts resulting from suspension of the common units distribution accumulate, while those related to the subordinated units do not. In the future if and as distributions are made for any quarter, the first priority is to pay the then minimum quarterly distribution to common unitholders (including the holders of common unit warrants). Any additional distribution amounts paid at that time are then paid to common unitholders (including the holders of common unit warrants) until their previously unpaid accumulated arrearage amounts have been paid in full. As of December 31, 2013, the total arrearage amount was $25.3 million. In the first quarter 2013, due to continued weakness in the coal markets, distributions related to the fourth quarter 2012 and going forward were suspended to further preserve liquidity. Distributions are also prohibited by the Financing Agreements as long as we have outstanding borrowings thereunder.

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Note 21 - Segment Information (Details)	12 Months Ended
	Dec. 31, 2013
Segment Reporting [Abstract]
Number of Operating Segments	1
Number of Operating Subsidiaries	3

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Note 9 - Reclamation and Mine Closure Costs

12 Months Ended

Dec. 31, 2013

Asset Retirement Obligation Disclosure [Abstract]

Asset Retirement Obligation Disclosure [Text Block]

NOTE 9: RECLAMATION AND MINE CLOSURE COSTS

As previously indicated, our reclamation and mine closure costs arise from SMCRA and similar state statutes, which require that mine property be restored in accordance with specified standards and an approved reclamation plan. The required reclamation activities to be performed are outlined in our mining permits. These activities include reclaiming the pit and support acreage, as well as stream mitigation.

As of December 31, 2013, our liability for reclamation and mine closure costs totaled $31.7 million, including amounts reported as current liabilities. While the precise amount of these future costs cannot be determined with certainty, we estimate that, as of December 31, 2013, the aggregate undiscounted cost of final reclamation and mine closure is $39.7 million.

Activities affecting the liability for reclamation and mine closure costs for the respective years are as follows:

	Year Ended December 31,
	2013			2012
Beginning balance	$	29,013		$	21,789
Accretion expense		2,293			1,567
Payments		(8,656	)		(8,966	)
Revisions in estimated cash flows		9,004			14,623
Total reclamation and mine closure costs		31,654			29,013
Less current portion		(5,996	)		(3,869	)
Noncurrent liability	$	25,658		$	25,144

In 2013, the revisions in discounted estimated cash flows resulted in a net increase in the reclamation and mine closure costs of $9.0 million. Of this amount, $3.7 million related to four new mines, $4.0 million related to reclamation work in progress at recently closed mines and the remaining $1.3 million related to updated cost estimates for pond removal, grading and water treatment.

In 2012, the revisions in discounted estimated cash flows resulted in a net increase in the reclamation and mine closures costs of $14.6 million. Of this amount, $5.7 million related to eight new mines, $3.6 million related to reclamation work in progress at recently closed mines and $1.5 million related to estimated closing costs and timing for two mines being closed earlier than anticipated, with the remaining $3.8 million due to revisions to estimates of expected costs. The accelerated closures are a result of the restructuring plan for our Illinois Basin operations, which we began implementing in the first quarter of 2012, as further discussed in Note 3.

Adjustments to the liability for reclamation and mine closure costs due to such revisions generally result in corresponding adjustments to the related mine development assets for active and new mines.

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Note 7 - Intangible Assets (Details) - Expected Amortization of Identifiable Intangible Assets (USD $) In Thousands, unless otherwise specified	Dec. 31, 2013
Expected Amortization of Identifiable Intangible Assets [Abstract]
For the years ending December 31, 2014	$ 227
2015	204
2016	183
2017	126
2018	84
Thereafter	$ 364

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Note 7 - Intangible Assets

12 Months Ended

Dec. 31, 2013

Disclosure Text Block [Abstract]

Intangible Assets Disclosure [Text Block]

NOTE 7: INTANGIBLE ASSETS

	As of December 31, 2013
	Estimated Remaining Life (years)		Cost		Accumulated Amortization		Net Carrying Value
Intangible assets
Customer relationships		13	$	3,315	$	2,127	$	1,188

	As of December 31, 2012
	Estimated Remaining Life (years)		Cost		Accumulated Amortization		Net Carrying Value
Intangible assets
Customer relationships		14	$	3,315	$	1,873	$	1,442

Customer relationships represent intangible assets that were recorded at fair value when we acquired Oxford Mining and its subsidiaries in August 2007. The net carrying value of our customer relationships is reflected in our consolidated balance sheets as “intangible assets, net.” We amortize these assets over the expected life of the respective customer relationships. Amortization related to customer relationships totaled $254, $242, and $273 for the years ended December 31, 2013, 2012 and 2011, respectively.

Expected amortization of intangible assets will be approximately:

For the years ending December 31, 2014	$	227
2015		204
2016		183
2017		126
2018		84
Thereafter		364

We evaluate our intangible assets for impairment when indicators of impairment exist. For the years ended December 31, 2013, 2012 and 2011, there were no indicators of impairment present for our intangible assets.

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Note 8 - Other Long-term Assets and Other Current Liabilities

12 Months Ended

Dec. 31, 2013

Other Longterm Assets And Other Current Liabilities [Abstract]

Other Longterm Assets And Other Current Liabilities [Text Block]

NOTE 8: OTHER LONG-TERM ASSETS AND OTHER CURRENT LIABILITIES

Other long-term assets consisted of the following:

	As of December 31,
	2013		2012
Reclamation bond collateral(1)	$	9,582	$	-
Deferred financing costs, net(1)		7,644		2,061
Restricted cash		3,969		3,929
Deposits		1,526		1,070
Other		100		117
Total	$	22,821	$	7,177

Other current liabilities consisted of the following:

	As of December 31,
	2013		2012
Accrued interest and interest rate swap(2)	$	1,424	$	709
Accrued royalties		1,062		815
Other		971		967
Total	$	3,457	$	2,491

(1)	See Note 10.
(2)	See Note 11 regarding interest rate swap.

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Note 10 - Long-Term Debt

12 Months Ended

Dec. 31, 2013

Disclosure Text Block [Abstract]

Long-term Debt [Text Block]

NOTE 10: LONG-TERM DEBT

Debt consisted of the following:

	As of December 31,
	2013			2012
Credit facilities:
First lien debt:
Term loan	$	69,321		$	45,000
Revolving line of credit		19,500			92,000
Second lien debt:
Term loan		70,862			-
Other obligations		3,593			7,527
Total debt		163,276			144,527
Less current portion		(7,901	)		(102,970	)
Long-term debt	$	155,375		$	41,557

Credit Facilities Generally

In connection with our initial public offering in July 2010, we entered into an agreement for our credit facility (our “2010 Credit Agreement”) which provided for a $115 million revolving credit line that matured in July 2013 and a $60 million term loan that would have matured in July 2014. We were required to make quarterly principal payments of $1.5 million on the term loan that commenced in September 2010 and continue until maturity when the remaining balance was to be paid. Borrowings under our 2010 Credit Agreement bore interest at a variable rate per annum equal to, at our option, the London Interbank Offered Rate (“LIBOR”) or the Base Rate plus the Applicable Margin (Base Rate and Applicable Margin are defined in our 2010 Credit Agreement).

In June 2012, we executed an amendment to our 2010 Credit Agreement which was applicable for the remaining term. The amendment (i) modified the leverage ratio, (ii) authorized the sale of certain Kentucky assets, and (iii) allowed for quarterly distributions at specified minimum levels or at higher levels as long as specified liquidity thresholds were maintained. In connection with the amendment, we paid the consenting lenders a non-refundable amendment fee equal to 0.50% of their then outstanding loan commitments.

In June 2013, we closed on $175 million of credit facilities that replaced and was used to pay our 2010 Credit Agreement borrowings in full. These facilities include (i) a first lien credit facility consisting of a $75 million term loan and a $25 million revolver under a financing agreement (the “First Lien Financing Agreement”) and (ii) a second lien credit facility consisting of a $75 million term loan (with an option for an additional $10 million term loan if requested by us and approved by the issuing second lien lender) under a financing agreement (the “Second Lien Financing Agreement,” and collectively with the First Lien Financing Agreement, the “Financing Agreements”).

The first lien credit facility matures in September 2015 with an option to extend to June 2016, and the second lien credit facility matures in December 2015 with an option to extend to September 2016, if certain conditions are met. As of December 31, 2013, the blended cash interest rate for both credit facilities was 9.53%. The Financing Agreements contain customary financial and other covenants, and also preclude making unitholder distributions during the term of the credit facilities. Borrowings under the credit facilities are secured by substantially all of our assets. Proceeds of the credit facilities were used to retire our previous revolving credit line and term loan under our 2010 Credit Agreement, to cash collateralize letters of credit and to pay fees and expenses related to the credit facilities.

As of December 31, 2013, we were in compliance with all covenants under the terms of the Financing Agreements.

Warrants

In conjunction with the Second Lien Financing Agreement, certain lenders and lender affiliates received warrants entitling them to purchase 1,955,666 common units and 1,814,185 subordinated units at $0.01 per unit. The warrants participate in distributions whether or not exercised. During the five-year term for exercise of the warrants, the warrant exercise price and number of units will be adjusted for unit splits or reverse splits, such that the economics of the warrants remain unchanged. These warrants are freestanding financial instruments, within the scope of ASC 480, Distinguishing Liabilities from Equity, since they are detachable from the Second Lien Financing Agreement. The warrants, classified as a liability, were recorded at their fair value of $7.9 million at issuance. The warrants are subsequently marked to fair value with the change in fair value reported in earnings. The fair value assigned to the warrants at issuance was recorded as a debt discount, reducing the outstanding debt balance. This discount will be amortized through interest expense over the life of the second lien credit facility using the effective interest method. For the year ended December 31, 2013, the fair value of the warrants decreased $3.3 million. See Note 11 for fair value disclosures.

First Lien Credit Facility

As of December 31, 2013, we had a term loan of $69.3 million outstanding under the first lien credit facility. We are obligated to make quarterly principal payments of $1.3 million commencing in June 2014, until repayment of the then outstanding balance at maturity. Borrowings on the term loan bear interest at a variable rate per annum equal to, at our option, the London Interbank Offered Rate (“LIBOR”) (floor of 1.5%) plus 6.75% or the Reference Rate (as defined in the First Lien Financing Agreement) (floor of 3.00%) plus 6.25%. As of December 31, 2013, the first lien term loan had a cash interest rate of 8.25%, consisting of LIBOR of 1.5% plus 6.75%.

The first lien credit facility also includes a $25 million revolving credit facility under which $19.5 million was outstanding as of December 31, 2013. Of this amount, $9.6 million is used to collateralize reclamation bonds. The revolving credit facility bears interest at the same rates as the term loan under the first lien credit facility. As of December 31, 2013, the balance outstanding on the revolving credit facility had a weighted average cash interest rate of 8.76%, consisting of either LIBOR of 1.5% plus 6.75% or the Reference Rate of 3.25% plus 6.25%. As of December 31, 2013, we had $5.1 million of borrowing capacity available on the revolving credit facility.

The Financing Agreements require mandatory prepayment of principal with proceeds from certain events. During the year ended December 31, 2013, we paid down $5.7 million of the first lien term loan with proceeds from the sale of oil and gas rights in late June 2013 and the granting of a pipeline right-of-way to a third party in September 2013.

Second Lien Credit Facility

A portion of the $75 million of principal associated with the term loan issued under the second lien credit facility was allocated to the warrants in an amount equal to their fair value at issuance of $7.9 million. The value allocated to the warrants was recorded as a debt discount, with the remaining $67.1 million assigned to the term loan. The debt discount will be amortized to interest expense over the life of the second lien credit facility using the effective interest method.  Amortization of the debt discount totaled $1.5 million for the year ended December 31, 2013.

We are obligated to make quarterly principal payments of $0.2 million commencing in June 2014, until repayment of the then outstanding balance at maturity. The term loan under the second lien credit facility bears cash interest at a variable rate per annum equal to, at our option, LIBOR (floor of 1.25%) plus 9.75% or the Reference Rate (as defined in the Second Lien Financing Agreement) (floor of 3.00%) plus 11.75%. As of December 31, 2013, the second lien credit facility term loan had a cash interest rate of 11.00%, consisting of LIBOR of 1.25% plus 9.75%.

The second lien credit facility also provides for “PIK Interest” (paid-in-kind interest as defined in the Second Lien Financing Agreement) at the rate of 5.75%. PIK Interest is added quarterly to the then outstanding principal amount of the term loan as additional principal obligations. PIK Interest totaled $2.3 million for the year ended December 31, 2013.

As of December 31, 2013, the outstanding balance on the second lien term loan was $70.9 million. This amount represents the principal balance of $75.0 million, plus PIK Interest of $2.3 million, net of the unamortized debt discount of $6.4 million. 

Other Obligations

CONSOL Coal Reserves – In August 2010, Harrison Resources acquired coal reserves from CONSOL Energy, through one of its subsidiaries, in exchange for a down payment of $850 and a note payable in an original face amount of $13,458 that matures three years from the date of issuance to Harrison Resources of the permit to mine such reserves. This note is payable in three annual installments of $5,383, $5,383 and $2,692 commencing with the issuance of such permit in September 2012. This note has no stated interest rate; therefore, the difference between the face amount and the imputed amount was recorded as a discount using an imputed interest rate of 5.5% and is being amortized into interest expense using the effective interest method. As of December 31, 2013 and 2012, the outstanding balance on the CONSOL #3 loan was $2,584 and $7,508, respectively.

AEP Conesville Coal Preparation Plant – In April 2013, Oxford Conesville, LLC, a wholly-owned subsidiary of Oxford Mining, acquired the assets of the AEP Conesville coal preparation plant for $488 in cash, a $1,000 note at the rate of 5.00% and the assumption of the reclamation obligation. The note is payable in two installments payments of $500 due on April 5, 2014 and December 31, 2014.

Other Note Payable– We acquired coal reserves from an individual with payments due of $5 per year for ten years at no stated interest rate. The obligation matures in April 2015. The difference between the face amount and the imputed amount was recorded as a discount using an imputed interest rate of 6.75% and is being amortized into interest expense using the effective interest method.

Debt Maturity Table

The total debt of the Partnership matures as follows:

During the years ending December 31, 2014	$	7,901
2015		155,375
	$	163,276

Deferred Financing Costs

During the year ended December 31, 2013, net deferred financing costs totaling $0.8 million related to the credit facility under our 2010 Credit Agreement were written-off as interest expense and we capitalized $9.6 million of deferred financing costs related to our new credit facilities under the Financing Agreements.  These costs, included in “other long-term assets,” represent fees paid to lenders and advisors and for legal services. Amortization of deferred financing costs included in interest expense was $3,986, $2,175, and $1,600 for the year ended December 31, 2013, 2012 and 2011, respectively.

Selling, general and administrative expenses for 2013 included $0.7 million of fees paid to advisors and for legal services related to our credit facility refinancing, and $2.4 million of fees paid to lenders and advisors and for legal services related to the attempted refinancing of our credit facility under our 2010 Credit Agreement. There were no such expenses during the years ended December 31, 2012 and 2011.

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Note 9 - Reclamation and Mine Closure Costs (Details) - Asset Retirement Obligations Activity (USD $) In Thousands, unless otherwise specified	12 Months Ended
	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
Asset Retirement Obligations Activity [Abstract]
Beginning balance	$ 29,013	$ 21,789
Accretion expense	2,293	1,567	1,503
Payments	(8,656)	(8,966)
Revisions in estimated cash flows	9,004	14,623
Total reclamation and mine closure costs	31,654	29,013	21,789
Less current portion	(5,996)	(3,869)
Noncurrent liability	$ 25,658	$ 25,144

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Note 22 - Supplemental Quarter Financial Information (Unaudited) (Details) - Consolidated Quarterly Operating Results (USD $) In Thousands, except Per Share data, unless otherwise specified	3 Months Ended								12 Months Ended
	Dec. 31, 2013	Sep. 30, 2013	Jun. 30, 2013	Mar. 31, 2013	Dec. 31, 2012	Sep. 30, 2012	Jun. 30, 2012	Mar. 31, 2012	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
Note 22 - Supplemental Quarter Financial Information (Unaudited) (Details) - Consolidated Quarterly Operating Results [Line Items]
Total revenues	$ 82,330	$ 87,586	$ 88,125	$ 88,726	$ 86,498	$ 97,214	$ 91,948	$ 97,867	$ 346,767	$ 373,527	$ 400,377
Net (loss) income from operations	(3,972)	(1,036)	2,434	(3,356)	(2,904)	(29)	1,338	(12,968)	(5,930)	(14,563)	1,528
Net loss attributable to Oxford Resource
Partners, LP unitholders	(8,269)	(5,599)	(4,510)	(6,547)	(6,263)	(3,314)	(1,455)	(15,776)	(24,925)	(26,808)	(13,077)
Net loss allocated to general partner	(165)	(112)	(89)	(131)	(125)	(66)	(29)	(315)	(497)	(535)	(261)
Net loss allocated to limited partners	$ (8,104)	$ (5,487)	$ (4,421)	$ (6,416)	$ (6,138)	$ (3,248)	$ (1,426)	$ (15,461)	$ (24,428)	$ (26,273)	$ (12,816)
Loss per limited partner unit:
Basic (in Dollars per share)	$ (0.33)	$ (0.22)	$ (0.21)	$ (0.31)	$ (0.29)	$ (0.16)	$ (0.07)	$ (0.75)	$ (1.07)	$ (1.27)	$ (0.62)
Diluted (in Dollars per share)	$ (0.33)	$ (0.22)	$ (0.21)	$ (0.31)	$ (0.29)	$ (0.16)	$ (0.07)	$ (0.75)	$ (1.07)	$ (1.27)	$ (0.62)
Limited partners:
General partner (in Dollars per share)					$ 0.1000	$ 0.2688	$ 0.2688	$ 0.4375	$ 0	$ 1.0750	$ 1.7500
Common Units [Member]
Limited partners:
Distributions paid per unit, limited partners (in Dollars per share)					$ 0.2000	$ 0.4375	$ 0.4375	$ 0.4375		$ 1.5125
Subordinated Units [Member]
Limited partners:
Distributions paid per unit, limited partners (in Dollars per share)						$ 0.1000	$ 0.1000	$ 0.4375		$ 0.6375

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Note 10 - Long-Term Debt (Details) - Total Borrowings (USD $) In Thousands, unless otherwise specified	Dec. 31, 2013	Dec. 31, 2012
Debt Instrument [Line Items]
Other obligations	$ 3,593	$ 7,527
Total debt	163,276	144,527
Less current portion	(7,901)	(102,970)
Long-term debt	155,375	41,557
First Lien Debt [Member] | Term Loan [Member]
Debt Instrument [Line Items]
Borrowings	69,321	45,000
First Lien Debt [Member] | Revolving Credit Facility [Member]
Debt Instrument [Line Items]
Borrowings	19,500	92,000
Second Lien Debt [Member] | Term Loan [Member]
Debt Instrument [Line Items]
Borrowings	70,862	0
Revolving Credit Facility [Member]
Debt Instrument [Line Items]
Borrowings	$ 19,500

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Note 9 - Reclamation and Mine Closure Costs (Details) (USD $)	12 Months Ended
	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
Note 9 - Reclamation and Mine Closure Costs (Details) [Line Items]
Asset Retirement Obligation	$ 31,654,000	$ 29,013,000	$ 21,789,000
Asset Retirement Obligation, Revision of Estimate	9,004,000	14,623,000
Estimated Final Reclamation and Mine Closure Cost (Member)
Note 9 - Reclamation and Mine Closure Costs (Details) [Line Items]
Undiscounted Aggregate Mine Closure	39,700,000
Four New Mines [Member]
Note 9 - Reclamation and Mine Closure Costs (Details) [Line Items]
Asset Retirement Obligation, Revision of Estimate	3,700,000
Pond Removal & Water Treatment [Member]
Note 9 - Reclamation and Mine Closure Costs (Details) [Line Items]
Asset Retirement Obligation, Revision of Estimate	4,000,000
Reclamation Work in Progress [Member]
Note 9 - Reclamation and Mine Closure Costs (Details) [Line Items]
Asset Retirement Obligation, Revision of Estimate	1,300,000	3,600,000
eight new mines (Member)
Note 9 - Reclamation and Mine Closure Costs (Details) [Line Items]
Asset Retirement Obligation, Revision of Estimate		5,700,000
Estimated Closing Costs and Timing for Two Mines [Member]
Note 9 - Reclamation and Mine Closure Costs (Details) [Line Items]
Asset Retirement Obligation, Revision of Estimate		1,500,000
Revisions To Estimates Of Expected Costs [Member]
Note 9 - Reclamation and Mine Closure Costs (Details) [Line Items]
Asset Retirement Obligation, Revision of Estimate		$ 3,800,000

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Note 6 - Operating Leases (Tables)

12 Months Ended

Dec. 31, 2013

Operating Leases [Abstract]

Operating Leases of Lessee Disclosure [Table Text Block]

For the years ending December 31,   2014	$	7,928
2015		5,947
2016		2,642
2017		651
2018		2

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Note 3 - Impairment and Restructuring Expenses (Details) - Restructuring Charge Impairments and Expenses Expected to be Incurred (USD $) In Thousands, unless otherwise specified	12 Months Ended	24 Months Ended
	Dec. 31, 2013	Dec. 31, 2013
Cash:
Expenses	$ 1,078
Incurred Expenses		3,975
Non-cash:
Asset impairment	0	12,753
Total non-cash restructuring expenses	683	13,436
Total impairment and restructuring expenses	1,761	17,411
Scenario, Forecast [Member] | Employee Severance [Member]
Cash:
Total Expected Expenses	1,887
Scenario, Forecast [Member] | Other Restructuring [Member]
Cash:
Total Expected Expenses	1,021
Scenario, Forecast [Member] | Equipment Relocation Costs [Member]
Cash:
Total Expected Expenses	1,178
Scenario, Forecast [Member] | Contract Termination [Member]
Cash:
Total Expected Expenses	23
Non-cash:
Coal lease termination costs	683
Coal lease termination costs	683
Scenario, Forecast [Member]
Cash:
Total Expected Expenses	4,109
Non-cash:
Asset impairment	12,753
Total non-cash restructuring expenses	13,436
Total impairment and restructuring expenses	17,545
Employee Severance [Member]
Cash:
Expenses	534
Incurred Expenses		1,887
Other Restructuring [Member]
Cash:
Expenses	26
Incurred Expenses		1,021
Equipment Relocation Costs [Member]
Cash:
Expenses	495
Incurred Expenses		1,044
Contract Termination [Member]
Cash:
Expenses	23
Incurred Expenses		23
Non-cash:
Coal lease termination costs	683	683
Coal lease termination costs	$ 683	$ 683

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Note 15 - Workers' Compensation and Black Lung

12 Months Ended

Dec. 31, 2013

Workers Compensation And Black Lung [Abstract]

Workers Compensation And Black Lung [Text Block]

NOTE 15: WORKERS’ COMPENSATION AND BLACK LUNG

We have no liabilities under state statutes and the Federal Coal Mine Health and Safety Act of 1969, as amended, to pay black lung benefits to eligible employees, former employees and their dependents. Under the Black Lung Benefits Revenue 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, with neither amount to exceed 4.4% of the gross sales price for the coal. For the years ended December 31, 2013, 2012 and 2011, we recorded $3.2 million, $3.6 million and $4.2 million, respectively, in our cost of coal sales related to this excise tax.

With regard to workers’ compensation, we are insured through state sponsored programs or an insurance carrier where there is no state sponsored program.

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Note 20 - Supplemental Cash Flow Information

12 Months Ended

Dec. 31, 2013

Supplemental Cash Flow Elements [Abstract]

Cash Flow, Supplemental Disclosures [Text Block]

NOTE 20: SUPPLEMENTAL CASH FLOW INFORMATION

Supplemental cash flow information:

	For the Year Ended December 31,
	2013		2012		2011
Cash paid for:
Interest	$	12,258	$	10,739	$	6,976
Non-cash activities:
Coal reserves acquired with debt		-		307		-
Property and equipment acquired with debt		1,000		-		-
Reclamation and mine closure costs capitalized in mine development		8,927		16,011		12,278
Value of debt assigned to warrants		7,879		-		-
Market value of common units vested in LTIP		330		849		2,055

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Note 3 - Impairment and Restructuring Expenses (Details) (USD $)	1 Months Ended	12 Months Ended
	Mar. 31, 2012 T	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2013 Scenario, Forecast [Member]	Mar. 31, 2013 Reclassified from Assets Held for Sale [Member]
Note 3 - Impairment and Restructuring Expenses (Details) [Line Items]
Amount of Coal (in US Ton)	800,000
Impairment of Long-Lived Assets to be Disposed of		$ 0	$ 12,800,000
Machinery and Equipment, Gross		202,663,000	195,321,000		6,100,000
Restructuring Charges		1,800,000	2,900,000
Restructuring and Related Cost, Number of Positions Eliminated		35	200
Restructuring and Related Cost, Expected Cost Remaining				$ 100,000

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Note 13 - Earnings (Losses) Per Unit (Tables)

12 Months Ended

Dec. 31, 2013

Earnings Per Share [Abstract]

Schedule of Earnings Per Share, Basic and Diluted [Table Text Block]

	For the Year Ended December 31,
	2013			2012			2011
Limited partner units
Average units outstanding:
Basic		22,776,481			20,711,952			20,641,127
Effect of equity-based compensation	N/A			N/A			N/A
Diluted		22,776,481			20,711,952			20,641,127
Net loss allocated to limited partners
Basic	$	(24,470	)	$	(26,273	)	$	(12,816	)
Diluted		(24,470	)		(26,273	)		(12,816	)
Net loss per limited partner unit
Basic	$	(1.07	)	$	(1.27	)	$	(0.62	)
Diluted		(1.07	)		(1.27	)		(0.62	)
General partner units
Average units outstanding:
Basic and diluted		423,618			422,609			421,038
Net loss allocated to general partner
Basic	$	(455	)	$	(535	)	$	(261	)
Diluted		(455	)		(535	)		(261	)
Net loss per general partner unit
Basic	$	(1.07	)	$	(1.27	)	$	(0.62	)
Diluted		(1.07	)		(1.27	)		(0.62	)
Anti-dilutive units (1) (2)		-			-			68,760
Distributions paid per unit:
Limited partners:
Common	$	-		$	1.5125		$	1.7500
Subordinated		-			0.6375			1.7500
General partner		-			1.0750			1.7500

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Consolidated Statements of Partners' Capital (Deficit) (USD $) In Thousands, except Share data	Common Units [Member]	Subordinated [Member]	Limited Partners [Member]	General Partner [Member]	Noncontrolling Interest [Member]	Total
Balance at Dec. 31, 2010	$ 146,078	$ (40,394)	$ 105,684	$ (63)	$ 3,142	$ 108,763
Balance (in Shares) at Dec. 31, 2010	10,330,603	10,280,380	20,610,983	420,633
Net (loss) income	(6,437)	(6,379)	(12,816)	(261)	4,748	(8,329)
Partners’ contributions				28		28
Partners’ contributions (in Shares)				1,411
Partners’ distributions	(18,129)	(17,978)	(36,107)	(736)	(4,901)	(41,744)
Equity-based compensation	1,077		1,077			1,077
Issuance of units to LTIP participants	(678)		(678)			(678)
Issuance of units to LTIP participants (in Shares)	69,141		69,141
Balance at Dec. 31, 2011	121,911	(64,751)	57,160	(1,032)	2,989	59,117
Balance (in Shares) at Dec. 31, 2011	10,399,744	10,280,380	20,680,124	422,044
Net (loss) income	(13,237)	(13,036)	(26,273)	(535)	755	(26,053)
Partners’ contributions				12		12
Partners’ contributions (in Shares)				1,450
Partners’ distributions	(15,772)	(6,550)	(22,322)	(455)		(22,777)
Equity-based compensation	1,262		1,262			1,262
Issuance of units to LTIP participants	(234)		(234)			(234)
Issuance of units to LTIP participants (in Shares)	71,066		71,066
Balance at Dec. 31, 2012	93,930	(84,337)	9,593	(2,010)	3,744	11,327
Balance (in Shares) at Dec. 31, 2012	10,470,810	10,280,380	20,751,190	423,494
Net (loss) income	(12,374)	(12,054)	(24,428)	(497)	1,225	(23,700)
Equity-based compensation	1,441		1,441			1,441
Issuance of units to LTIP participants	(66)		(66)			(66)
Issuance of units to LTIP participants (in Shares)	115,883		115,883
Balance at Dec. 31, 2013	$ 82,931	$ (96,391)	$ (13,460)	$ (2,507)	$ 4,969	$ (10,998)
Balance (in Shares) at Dec. 31, 2013	10,586,693	10,280,380	20,867,073	423,494

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Note 4 - Inventory

12 Months Ended

Dec. 31, 2013

Inventory Disclosure [Abstract]

Inventory Disclosure [Text Block]

NOTE 4: INVENTORY

Inventory consisted of the following:

	As of December 31,
	2013		2012
Coal	$	5,957	$	5,609
Fuel		1,879		1,893
Spare parts and supplies		6,004		5,052
Total	$	13,840	$	12,554

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Note 7 - Intangible Assets (Details) (USD $) In Thousands, unless otherwise specified	12 Months Ended
	Dec. 31, 2013		Dec. 31, 2012		Dec. 31, 2011
Note 7 - Intangible Assets (Details) [Line Items]
Amortization of Intangible Assets	$ 254	[1]	$ 242	[1]	$ 273	[1]
Customer Relationships [Member]
Note 7 - Intangible Assets (Details) [Line Items]
Amortization of Intangible Assets	$ 254		$ 242		$ 273

[1] See Note 7.

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Note 19 - Related Party Transactions (Details) (USD $) In Thousands, unless otherwise specified	12 Months Ended
	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
Note 19 - Related Party Transactions (Details) [Line Items]
Notice Period for Terminating Service Agreement	30 days
Accounts Payable, Related Parties, Current	$ 624	$ 3,442
Proceeds from Sale of Property, Plant, and Equipment	6,424	12,417	849
Tunnell Hill [Member]
Note 19 - Related Party Transactions (Details) [Line Items]
Proceeds from Sale of Property, Plant, and Equipment		877
Revenue from Related Parties	385	205	1,525
Accounts Receivable, Related Parties	83
Zanesville Aviation [Member]
Note 19 - Related Party Transactions (Details) [Line Items]
Related Party Transaction, Expenses from Transactions with Related Party	$ 97	$ 146	$ 178

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Note 11 - Fair Value of Financial Instruments (Details) - Financial Instruments Measured at Fair Value on a Recurring Basis (Fair Value, Inputs, Level 2 [Member], USD $) In Thousands, unless otherwise specified	Dec. 31, 2013 Warrant [Member]	Dec. 31, 2012 Interest Rate Swap [Member]
Note 11 - Fair Value of Financial Instruments (Details) - Financial Instruments Measured at Fair Value on a Recurring Basis [Line Items]
Assets, fair value	$ (4,599)	$ (12)

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Note 21 - Segment Information

12 Months Ended

Dec. 31, 2013

Segment Reporting [Abstract]

Segment Reporting Disclosure [Text Block]

NOTE 21: SEGMENT INFORMATION

We operate in one business segment. We operate surface coal mines in Northern Appalachia and through December 2013 in the Illinois Basin and sell high-value thermal coal to utilities, industrial customers, municipalities and other coal-related entities primarily in the eastern United States. Our operating and executive management reviews and bases its decisions upon consolidated reports. Three of our operating subsidiaries extract coal utilizing surface-mining techniques and prepare it for sale to their customers. Such operating subsidiaries share customers and a particular customer may receive coal from any one of such operating subsidiaries.

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Note 13 - Earnings (Losses) Per Unit (Details) - Computation of Earnings Per Unit (USD $) In Thousands, except Share data, unless otherwise specified	3 Months Ended								12 Months Ended
	Dec. 31, 2013	Sep. 30, 2013	Jun. 30, 2013	Mar. 31, 2013	Dec. 31, 2012	Sep. 30, 2012	Jun. 30, 2012	Mar. 31, 2012	Dec. 31, 2013		Dec. 31, 2012		Dec. 31, 2011
Average units outstanding:
Basic (in Shares)									22,776,481		20,711,952		20,641,127
Effect of equity-based compensation (in Shares)
Diluted (in Shares)									22,776,481		20,711,952		20,641,127
Net loss allocated to limited partners
Nеt loss allocatеd to limitеd partnеrs (in Dollars)	$ (8,104)	$ (5,487)	$ (4,421)	$ (6,416)	$ (6,138)	$ (3,248)	$ (1,426)	$ (15,461)	$ (24,428)		$ (26,273)		$ (12,816)
Net loss per limited partner unit
Nеt loss pеr limitеd partnеr unit	$ (0.33)	$ (0.22)	$ (0.21)	$ (0.31)	$ (0.29)	$ (0.16)	$ (0.07)	$ (0.75)	$ (1.07)		$ (1.27)		$ (0.62)
Average units outstanding:
Basic and diluted (in Shares)									423,618,000		422,609,000		421,038,000
Net loss allocated to general partner
Nеt loss allocatеd to gеnеral partnеr (in Dollars)	(165)	(112)	(89)	(131)	(125)	(66)	(29)	(315)	(497)		(535)		(261)
Net loss per general partner unit
Anti-dilutive units (1) (2) (in Shares)										[1],[2]		[1],[2]	68,760,000	[1],[2]
Limited partners:
General partner					$ 0.1000	$ 0.2688	$ 0.2688	$ 0.4375	$ 0		$ 1.0750		$ 1.7500
Basic (Member)
Average units outstanding:
Basic (in Shares)									22,776,481,000		20,711,952,000		20,641,127,000
Net loss allocated to limited partners
Nеt loss allocatеd to limitеd partnеrs (in Dollars)									(24,470)		(26,273)		(12,816)
Net loss per limited partner unit
Nеt loss pеr limitеd partnеr unit									$ (1.07)		$ (1.27)		$ (0.62)
Net loss allocated to general partner
Nеt loss allocatеd to gеnеral partnеr (in Dollars)									(455)		(535)		(261)
Net loss per general partner unit
Nеt loss pеr gеnеral partnеr unit									$ (1.07)		$ (1.27)		$ (0.62)
Diluted (Member)
Average units outstanding:
Diluted (in Shares)									22,776,481,000		20,711,952,000		20,641,127,000
Net loss allocated to limited partners
Nеt loss allocatеd to limitеd partnеrs (in Dollars)									(24,470)		(26,273)		(12,816)
Net loss per limited partner unit
Nеt loss pеr limitеd partnеr unit									$ (1.07)		$ (1.27)		$ (0.62)
Net loss allocated to general partner
Nеt loss allocatеd to gеnеral partnеr (in Dollars)									$ (455)		$ (535)		$ (261)
Net loss per general partner unit
Nеt loss pеr gеnеral partnеr unit									$ (1.07)		$ (1.27)		$ (0.62)
Common Units [Member]
Limited partners:
Limitеd partnеrs									$ 0		$ 1.5125		$ 1.7500
Subordinated Units [Member]
Limited partners:
Limitеd partnеrs									$ 0		$ 0.6375		$ 1.7500

[1] Anti-dilutive units are not used in calculating diluted average units.

[2] Unvested LTIP units are not dilutive units for the years ended December 31, 2013 and 2012.

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Note 10 - Long-Term Debt (Tables)

12 Months Ended

Dec. 31, 2013

Disclosure Text Block [Abstract]

Schedule of Long-term Debt Instruments [Table Text Block]

	As of December 31,
	2013			2012
Credit facilities:
First lien debt:
Term loan	$	69,321		$	45,000
Revolving line of credit		19,500			92,000
Second lien debt:
Term loan		70,862			-
Other obligations		3,593			7,527
Total debt		163,276			144,527
Less current portion		(7,901	)		(102,970	)
Long-term debt	$	155,375		$	41,557

Schedule of Maturities of Long-term Debt [Table Text Block]

During the years ending December 31, 2014	$	7,901
2015		155,375
	$	163,276

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Note 14 - Noncontrolling Interest

12 Months Ended

Dec. 31, 2013

Noncontrolling Interest [Abstract]

Noncontrolling Interest Disclosure [Text Block]

NOTE 14: NONCONTROLLING INTEREST

Harrison Resources, a limited liability company, was formed in March 2006 by Oxford Mining to acquire coal properties, develop mine sites and mine coal for sale to customers. Effective January 30, 2007, 49% of Harrison Resources was sold to CONSOL Energy and its ownership interest is held by one of its subsidiaries. Harrison Resources’ revenues, which are included in our consolidated statements of operations, were $34,100, $34,518 and $38,664 for the years ended December 31, 2013, 2012 and 2011, respectively. Oxford Mining has a services agreement with Harrison Resources under which we perform mining and reclamation services for agreed-upon per ton prices. Additionally, Oxford Mining has a broker agreement with Harrison Resources under which we market the coal.

Harrison Resources’ cash, which is deemed to be restricted, primarily relates to funds set aside for reclamation obligations in the amounts of $3,969 and $3,929 as of December 31, 2013 and 2012, respectively, and is included in our consolidated balance sheets as “other long-term assets.” Harrison Resources’ total net assets as of December 31, 2013 and 2012 were $10,140 and $7,641, respectively.

Noncontrolling interest, which represents the 49% of Harrison Resources owned by CONSOL Energy through one of its subsidiaries, consists of the following:

	For the Year Ended December 31,
	2013		2012
Beginning balance	$	3,744	$	2,989
Net income		1,225		755
Ending balance	$	4,969	$	3,744