UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

	Form 10-K
ý	ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

For the fiscal year ended December 31, 2012

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

 

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(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     ý   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     ý     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.     ý   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).     ý   Yes     ¨   No

 

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	ý
	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     ý   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 approximately $71,577,000 as of June 30, 2012, based on the reported closing price of the common units as reported on the New York Stock Exchange on such date.

 

As of March 25 , 2013,  10,475,237 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

 

 

PART I

 

Introduction

This report is both our 2012 Annual Report to unitholders and our 2012 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

Going Concern Considerations

We have engaged and continue to engage in negotiations with the lenders for our existing credit facility to amend and extend the term of such credit facility (a “Credit Facility Amend and Extend”).  It has been an important endeavor for us because the revolving credit line portion of our credit facility matures in July 2013.  As we have been unable to achieve a Credit Facility Amend and Extend by the time of our filing of this Annual Report on Form 10-K (this “Annual Report”), we are unable to demonstrate that we have sufficient liquidity to operate our business over the next twelve months and thus substantial doubt is raised about our ability to continue as a going concern. Accordingly, the opinion issued by our independent registered public accounting firm (our “auditors”) in connection with the audit of our consolidated financial statements as of and for the year ended December 31, 2012 included in this Annual Report includes an emphasis paragraph reciting the existence of conditions that raise substantial doubt about our ability to continue as a going concern.   Our consolidated 2012 financial statements have been prepared assuming that we will continue as a going concern.   A ll amounts outstanding under the revolving credit line portion of our existing credit facility have been classified as current liabilities in our consolidated balance sheet as of December 31, 2012.  While o ur consolidated 2012 financial statements reflect significant asset impairment expenses for the fiscal year ended December 31, 2012, they do not include any adjustments relating to the recoverability and classification of asset carrying amounts or the amount of and classification of liabilities that may result should we be unable to continue as a going concern .

Our management has been actively working and will continue to work with the lenders to amend the provisions and extend the term of our existing credit facility.  However, there can be no assurance that we will be successful in amending and extending the facility.  Therefore, there can be no guarantee that our existing sources of cash and our future cash flows from operations will be adequate to meet our liquidity requirements, including cash requirements that are due under our existing credit facility or that are needed to fund our business operations. If we are unable to address our liquidity challenges, then our business and operating results could be materially adversely affected, potentially resulting in the need to curtail our business operations and/or reorganize our capital structure. Accordingly, there is substantial doubt that we will be able to continue as a going concern.

The credit agreement related to our existing credit facility, which became effective in July 2010, provides for a credit facility consisting of a $115 million revolving credit line that matures in July 2013, and a $60 million term loan that matures in July 2014. As of December 31, 2012, we had borrowings of $137.0 million outstanding consisting of $92.0 million on our revolving credit line and $45.0 million on our term loan. We also had $8.9 million of letters of credit outstanding in support of surety bonds, which bonds are primarily issued for reclamation obligations.

Overview

We are a low-cost producer and marketer of high-value steam coal (coal) to United States (“U.S.”) utilities and industrial users, and we are the largest producer of surface mined coal in Ohio. We focus on acquiring steam coal reserves that we can efficiently mine with our large-scale equipment. Our reserves and operations are strategically located to serve our primary market area of Illinois, Indiana, Kentucky, Ohio, Pennsylvania and West Virginia.

 

 

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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, 2012, management estimates that we owned or controlled approximately 86.4 million tons of coal reserves.  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, 2012, we sold 7.3 million tons of coal compared to 8.5 million tons for the year ended December 31, 2011, of which approximately 6.8 million and 8.1 million tons were produced from our mining activities and approximately 0.5 million and 0.4 million tons were purchased through brokered coal contracts (coal purchased from third parties for resale), at an average sale price of $49.65 and $46.23, respectively, for the years ended December 31, 2012 and 2011.   For the year ended December 31, 2012, we derived approximately 93.3% of our total coal revenues from sales to our ten largest customers, with the following top three customers and their affiliates accounting for approximately 72.6% of our coal revenues for that period: American Electric Power Company, Inc. (34.5%); FirstEnergy Corp. (23.0%); and East Kentucky Power Cooperative (15.1%).

In the first quarter of 2012, we received a termination notice from a customer related to an 0.8 million tons per year coal supply contract to be fulfilled from our Illinois Basin operations.   In response, we idled one Illinois Basin mine and the related wash plant, closed our Illinois Basin 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, 2012 , production continued at two mines.  We have redeployed certain Illinois Basin equipment to our Northern Appalachia operations and are seeking to sell certain excess mining equipment related to these idled operations.

Based on current market conditions, we intend to idle all production activity in the Illinois Basin by the end of 2013, and satisfy our remaining coal supply obligation with purchased coal, the purchase of which has already been contracted.  We anticipate that the remaining restructuring related to our Illinois Basin operations will be completed by the end of 2013 and cost an additional $0.9 million.

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, 2012.  Each of our two founders has over 40 ears of experience in the coal mining industry.  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 Energy, to mine surface coal reserves purchased from CONSOL Energy.  In September 2009, we acquired the active surface mining operations of Phoenix Coal Corporation (“Phoenix Coal”).  The Phoenix Coal acquisition provided us with an entry into the Illinois Basin in western Kentucky and included one mining complex comprised of four mines, as well as the Island river terminal on the Green River in western Kentucky.

 

 

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The Coal Industry

A major contributor to the world energy supply, coal-fired power plants currently fuel 41% of global 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 37.6% of the electricity produced in the United States in 2012.  The EIA forecasts the coal share of total electric power generation in the United States to rise from 37.6% in 2012 to 39.0% in 2013 and 39.6% in 2014, with steam coal remaining the dominant fuel source in the future.

The majority of coal consumed in the U.S. is used to generate electricity, with the balance used by a variety of industrial users to heat and power foundries, cement plants, paper mills, chemical plants and other manufacturing and processing facilities.  In 2012, coal-fired power plants produced approximately 37.6% of all electric power generation in the U.S.

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.  Coal used as fuel to generate electricity is commonly referred to as “steam coal” or “thermal coal.”

Coal has long been favored as an electricity generating fuel by regulated utilities because of its basic economic advantage.  The largest cost component in electricity generation is fuel.  Historically, coal has been considerably less expensive than natural gas or oil.  However, the growth of hydraulic fracturing (fracking) combined with the warm winter in early 2012 resulted in record high supplies and inventories of natural gas throughout most of 2012.  This oversupply altered the competitive balance throughout much of the year and allowed natural gas to gain market share in the power generation market compared to historical levels.

According to the EIA, the average wellhead price of natural gas in 2012 was $2.66, as compared to $3.95 and $4.48 in 2011 and 2010, respectively.  The 2012 price represents the lowest annual price since 1999.  As prices dropped, the number of drill rigs deployed for natural gas production declined, ending 2012 at 431 rigs according to Baker Hughes.  This compares to 809 and 919 rigs at the end of 2011 and 2010, respectively.  The decline in prices along with less development is believed to be an indicator that prices at this level do not provide enough incentive to expand drilling activity.  Therefore, we believe that natural gas prices are at unsustainably low levels.  We expect coal to recapture market share in the domestic electric power market as natural gas prices increase to more sustainable levels.

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 also generally higher in heat content (as measured in Btu), and therefore is desirable to utilities as fuel for electricity generation.  However, the premium price offered by steel makers for the metallurgical quality attributes is typically higher than the price offered by utility coal buyers that value only the heat content.

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

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

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

 

 

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Coal Mining Methods

Coal is mined using two primary methods, surface mining and underground mining.  For the year ended December 31, 2012, 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, 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 mountainous 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.

Highwall mining.   Highwall mining is a surface mining method generally utilized in conjunction with contour surface mining.  At a highwall contour mining operation, a modified continuous miner, with an attached beltline system, cuts horizontal passages from the face of a highwall into a seam.  These passages can penetrate to a depth of up to 1,600 feet.  This method can recover up to 65% of the reserve block penetrated.

Coal Preparation and Blending

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

Coal Characteristics

In general, coal of all geological composition is characterized by its end use as either steam coal or metallurgical coal.  Heat value and sulfur content are the most important variables in assessing the marketability and profitability of steam 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 steam coal, the characteristics of which are described below.

 

 

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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, as received.  Most coal found in the western U.S. ranges from 8,000 to 10,000 Btus per pound, as received.

Bituminous Coal

Bituminous coal is a relatively soft, black coal with a heat content that typically ranges from 10,000 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 U.S.  Industrial customers also use bituminous coal for steam purposes.

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 is coal which, when burned, emits approximately 1.6 pounds or less of sulfur dioxide per million Btus.  Mid-sulfur coal is characterized as coal which, 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 is generally characterized as coal which, 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 increases transportation costs, and electric generating plants must handle and dispose of ash following combustion.

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

Transportation

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

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

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

 

 

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In 2012, approximately 69.3% of our coal sales were delivered to our customers by barge, with the remaining 28.5% and 2.2% delivered by truck and rail, respectively.  We believe we enjoy 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, 2012, we operated 19 active surface mines and managed these mines as eight mining complexes located in eastern Ohio and western Kentucky.  These mining facilities include two preparation plants, each of which receive, wash, blend, process and ship coal produced from one or more of our 19 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.

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.  Each year, we endeavor to replace the oldest units, thereby maintaining productivity, while minimizing capital expenditures.

For the years ended December 31, 2012 and 2011, we produced 6.8 and 8.1 million tons of coal, respectively, and sold 7.3 and 8.5 million tons of coal, respectively, including 0.5 and 0.4 million tons of purchased coal, respectively.

As of December 31, 2012, we owned and/or controlled 86.4 million tons of proven and probable coal reserves, of which 62.1 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 2012, we acquired 7.2 million tons of proven and probable coal reserves, an amount approximately equal to 105.2% of our 2012 production.

 

 

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The following table summarizes our mining complexes, our coal production for the year ended December 31, 2012 and our coal reserves as of December 31, 2012:

 

						As of December 31, 2012
Mining Complexes		Production for the Year Ended December 31, 2012				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 - (principally Ohio)
Cadiz			1,903				8,437				8,295				142				11,400				3.5		Barge, Rail
Tuscarawas County			703				8,636				8,636				-				11,767				4.0		Truck
Plainfield			371				2,771				2,771				-				11,836				4.4		Truck
Belmont County			1,033				12,956				12,437				519				11,823				4.2		Barge
New Lexington			839				3,687				3,369				318				11,729				4.1		Rail
Harrison (3)			716				3,471				3,297				174				11,331				1.9		Barge, Rail, Truck
Noble County			231				2,741				2,554				187				11,296				4.9		Barge, Truck
Illinois Basin (Kentucky) Muhlenberg County			1,021				19,399				18,836				563				11,327				3.5		Barge, Truck
Total Surface Mining Operations			6,817				62,098				60,195				1,903
Underground Coal Reserves:
Northern Appalachia (Ohio)
Tusky (4)							24,343				18,977				5,366				12,900				2.1
Total Underground Coal Reserves							24,343				18,977				5,366
Total							86,441				79,172				7,269

 

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(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 Energy.  We own 51% of Harrison Resources and CONSOL Energy 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, 2012 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, 2012:

 

 

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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, 2012, our mining complexes in Northern Appalachia produced an aggregate of 5.8 million tons of steam coal.  The following table provides summary information regarding our mining complexes in Northern Appalachia for the years indicated:

		Transportation Facilities Utilized					Transportation		Number of Active Mines at December 31,				Tons Produced for the Years Ended December 31,
Mining Complex		River Terminal			Rail Loadout		Method (1)		2012				2012				2011				2010
													(in millions)
Cadiz		Bellaire			Cadiz		Barge, Rail			3				1.9				1.7				1.4
Tuscarawas County		—			—		Truck			5				0.7				0.9				0.9
Plainfield (3)		—			—		Truck			-				0.4				0.2				0.3
Belmont County		Bellaire			—		Barge			6				1.0				1.0				1.1
New Lexington		—			New Lexington		Rail			1				0.9				0.8				0.6
Harrison (2)		Bellaire			Cadiz		Barge, Rail, Truck			1				0.7				0.8				1.0
Noble County		Bellaire			—		Barge, Truck			1				0.2				0.4				0.5
Total										17				5.8				5.8				5.8

 

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(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 Energy.  We own 51% of Harrison Resources and CONSOL Energy 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.”

 

(3)

The Otsego mine at the Plainfield mining complex was idled in December 2012. In early 2013, we opened the Hunt mine, a new mine at the Plainfield 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 and Valley 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, 2012, the Cadiz mining complex included 8.4 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.  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, 2012.

Tuscarawas County Mining Complex

The Tuscarawas County mining complex is located in Tuscarawas, Columbiana and Stark Counties, Ohio, and currently consists of the Stonecreek, Stillwater, Strasburg, Rosebud Miller and East Canton 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, 2012, the Tuscarawas County mining complex included 8.6 million tons of proven and probable coal reserves.  Coal produced from the Tuscarawas County mining complex is transported by truck directly to our customers, our Barb Tipple blending and coal crushing facility or our Strasburg wash plant.  Coal trucked to our Barb Tipple blending and coal crushing facility or our Strasburg wash plant is then transported by truck to the customer after processing is completed.  This mining complex uses the area, contour, auger and highwall miner methods of surface mining.  The infrastructure at this mining complex includes three coal crushers with truck scales, the Stonecreek and Strasburg blending facilities and the Strasburg wash plant.  This mining complex produced 0.7 million tons of coal for the year ended December 31, 2012.

Plainfield Mining Complex

The Plainfield mining complex is located in Muskingum, Guernsey and Coshocton Counties, Ohio, and consisted of the Otsego mine, which we idled in December 2012.  In early 2013, we opened the Hunt mine, a new mine at the Plainfield mining complex.  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, 2012, 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 Strasburg wash plant and then transported by truck to the customer.  This mining complex uses contour, auger and highwall miner methods of surface mining.  The infrastructure at this mining complex includes our Barb Tipple blending and coal crushing facility and truck scale.  This mining complex produced 0.4 million tons of coal for the year ended December 31, 2012.

 

 

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Belmont County Mining Complex

The Belmont County mining complex is located in Belmont County, Ohio, and currently consists of the Bedway-Kaczor, Egypt Valley, Jeffco, Lafferty, Shugert and Wheeling Valley mines.  We began mining operations at this mining complex in 1999.  Operations at the Belmont County mining complex target the Pittsburgh #8 and Meigs Creek #9 coal seams.  As of December 31, 2012, the Belmont County mining complex included 13.0 million tons of proven and probable coal reserves.  Coal produced from this mining complex is primarily transported by truck to our Bellaire river terminal on the Ohio River.  Coal produced from this mining complex is crushed and blended at the Bellaire river terminal before it is loaded onto barges for shipment to our customers on the Ohio River.  This mining complex uses area, contour, auger and highwall miner methods of surface mining. This mining complex produced 1.0 million tons of coal for the year ended December 31, 2012.

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, Middle Kittanning #6 and Pittsburgh #8 coal seams.  As of December 31, 2012, the New Lexington mining complex included 3.7 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.  This mining complex uses the area, auger and highwall miner 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 0.9 million tons of coal for the year ended December 31, 2012.

Harrison Mining Complex

The Harrison mining complex is located in Harrison County, Ohio, and currently consists of the Harrison mine.  Mining operations at this mining complex began in 2007.  The Harrison mining complex is owned by Harrison Resources.  We own 51% of Harrison Resources and CONSOL Energy owns the remaining 49% indirectly through one of its subsidiaries.  We entered into this joint venture in 2007 to mine coal reserves purchased from CONSOL Energy.  We manage all of the operations of, and perform all of the contract mining and marketing services for, Harrison Resources.  Because the results of operations of Harrison Resources are included in our consolidated financial statements for the year ended December 31, 2012 as required by GAAP, coal production and proven and probable coal reserves attributable to the Harrison mining complex are presented on a gross basis, assuming we owned 100% of Harrison Resources.

Since its formation in 2007, Harrison Resources has acquired 6.9 million tons of proven and probable coal reserves from CONSOL Energy.  We believe that CONSOL Energy controls additional reserves in Harrison County, Ohio, that could be acquired by Harrison Resources in the future.  However, CONSOL Energy has no obligation to sell those reserves to Harrison Resources, and we have no assurance that Harrison Resources will be able to acquire those reserves 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, 2012, the Harrison mining complex included 3.5 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, 2012.

Noble County Mining Complex

The Noble County mining complex is located in Noble and Guernsey Counties, Ohio, and currently consists of the Shuman mine.  We began mining operations at this complex in 2006.  Operations at the Noble County mining complex target the Pittsburgh #8 and Meigs Creek #9 coal seams.  As of December 31, 2012, the Noble County mining complex included 2.7 million tons of proven and probable coal reserves.  Coal produced from this mining complex is trucked to our Bellaire river terminal on the Ohio River or to our Barb Tipple facility.  Coal trucked to our Bellaire river terminal is then transported by barge to the customer.  Coal trucked to our Barb Tipple blending and coal-crushing facility is transported by truck to the customer after processing is completed.  The Noble County mining complex uses the area, contour and auger methods of surface mining. This mining complex produced 0.2 million tons of coal for the year ended December 31, 2012.

 

 

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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, 2012.

 

 

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We operate one surface mining complex in the Illinois Basin, which is located in western Kentucky.  For the year ended December 31, 2012, this mining complex produced an aggregate of 1.0 million tons of steam coal.  The following table provides summary information regarding our mining complex in the Illinois Basin for the years indicated.

 

		Transportation Facilities Utilized											Tons Produced for the Year Ended December 31,
Mining Complex		River Terminal		Rail Loadout			Method (1)		Mines				2012				2011				2010
													(in millions)
Muhlenberg County		Island River			—		Barge, Truck			2				1.0				2.2				1.7

 

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(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 County Mining Complex

The Muhlenberg County mining complex, located in Muhlenberg and McLean Counties in western Kentucky, currently consists of the Briar Hill and 431 mines.  We began mining operations at this mining complex in October 2009.  Operations at the Muhlenberg County mining complex target the #5, #6, #9, #10, #11, #12 and #13 coal seams of the Illinois Basin.  As of December 31, 2012, the Muhlenberg County mining complex included 19.4 million tons of proven and probable coal reserves.  Coal produced from this mining complex is usually crushed at the mine site and then trucked to our Island river terminal on the Green River or directly to the customer.  Coal trucked to our Island river terminal is then transported to the customer by barge.  This mining complex uses the area method of surface mining.  The infrastructure at this mining complex includes one coal crusher, two truck scales and our Island river terminal.  This mining complex produced 1.0 million tons of steam coal during the year ended December 31, 2012.

Based on current market conditions, we intend to idle all production activity at this mining complex by the fourth quarter of 2013, and satisfy our remaining coal supply obligation with purchased coal for which we have already contracted.  We anticipate that the remaining restructuring related to our Illinois Basin operations will be completed by the end of 2013 and cost an additional $0.9 million.

As previously disclosed in our public filings, we received a termination notice in March 2012 from a customer related to an 0.8 million tons 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 and washed coal on certain sales contracts.  We have also taken legal action against the terminating customer for wrongful termination of the coal supply contract.

In the second quarter of 2012, we further adjusted our Illinois Basin operations, varying the mines that were idled to best manage strip ratio impacts and other costs.  We also resumed operations at the preparation plant on a limited basis.

In the third quarter of 2012, we idled one additional mine and resumed production at a second mine for a limited period of time that allowed us to meet our coal supply commitments.  The preparation plant continued to operate on a limited production basis through most of the quarter and then was again idled .

By the fourth quarter of 2012, production continued at two mines.  We have redeployed certain Illinois Basin equipment to our Northern Appalachia operations and are seeking to sell certain excess mining equipment related to these idled operations.

For the twelve months ended December 31, 2012, we recognized impairment and restructuring expenses of $15.7 million related to the restructuring of our 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;

 

 

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•

our Strasburg preparation plant near Strasburg, Ohio;

•

our Bellaire river terminal on the Ohio River;

•

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

•

our Stonecreek coal crushing facility located in Tuscarawas County, Ohio.

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 11 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, 2012, we recognized $1.5 million in royalty on the sublease of the Tusky mine.   In 2012, we also received an advance royalty payment of $2.2 million in exchange for a significant reduction in the amount of overriding royalty going forward.

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 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, 2012, we produced and sold 1.4 million tons of limestone, and our revenues included $5.9 million in limestone sales.

Other Operations

For the fiscal year ended December 31, 2012, we generated $1.2 million of revenue from a variety of other services we performed in connection with our surface mining operations.  This revenue included the following:

•

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

•

leasing fees we earned for leasing equipment and selling small amounts of coal and clay to Tunnell Hill Reclamation, LLC, a landfill operator and subsidiary of Tunnel Hill Partners, LP, an entity owned by our sponsors;

•

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

•

service fees we earned for providing barge loading services, to third-party coal providers, at our Island river terminal and transloading facility on the Green River in western Kentucky.

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 .

 

 

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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.  F or the year ended December 31, 2012, we derived approximately 93.3% of our total coal revenues from sales to our ten largest customers, with affiliates of the following top three customers accounting for approximately 72.6% of our coal revenues for that period: American Electric Power Company, Inc. (34.5%); FirstEnergy Corp. (23.0%); and East Kentucky Power Cooperative (15.1%).

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, 2012, approximately 95.9% 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.  We have also entered into brokered transactions to purchase coal to meet our 2013 sales commitments.

We have one contract below current market rates that we entered into during periods of lower coal prices.  As the net costs associated with producing coal have increased due to higher energy, transportation and steel prices, the price adjustment mechanisms within this long-term contract do not reflect current market prices.  This has resulted in the counterparty to this contract benefiting from below-market prices for our coal.

 

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 2012, we spent more than $145.4 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, conveyance structure, ventilation supplies 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.

 

 

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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 coal industry is intensely competitive.  Our main competitors are 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., Westmoreland Coal Company and various other smaller, independent producers.  The most important factors on which we compete are price, coal quality and characteristics, transportation costs, and the reliability of supply.  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, which accounted for approximately 92.7% of domestic coal consumption in 2012.  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, 2012, we had $8.9 million in letters of credit supporting $37.7 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 U.S. coal mining industry with respect to matters such as permitting and licensing requirements, employee health and safety, air quality standards, water pollution, plant and wildlife protection, the reclamation and restoration of mining properties, the discharge of materials into the environment, surface subsidence from underground mining and the effects of mining on groundwater quality and availability.  These laws and regulations have had, and will continue to have, a significant effect on our costs of production and competitive position.  Future legislation, regulations or orders may be adopted or become effective which may adversely affect our mining operations, cost structure or the ability of our customers to use coal.  For instance, new legislation, regulations or orders, as well as future interpretations and more rigorous enforcement of existing laws, may require substantial increases in equipment and operating costs to us and delays, interruptions or a termination of operations, the extent of which we cannot predict.  Future legislation, regulations or orders or negative perceptions due to environmental issues may also cause coal to become a less attractive fuel source, resulting in a reduction in coal’s share of the market for fuels used to generate electricity.

We endeavor to conduct our mining 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 during mining operations occur from time to time in the industry and at our operations.

 

 

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Mining Permits and Approvals

Numerous governmental permits and approvals are required for mining operations.  In connection with obtaining these permits and approvals, we may be required to prepare and present to federal, state or local authorities data pertaining to the effect or impact that any proposed production or processing of coal 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 operations and could have a material adverse effect on our business.  Applications for permits are subject to public comment and may be subject to litigation from third parties seeking to deny issuance of a permit, which may also delay commencement or continuation of mining operations and could have a material adverse effect on our business.  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 addition, legislation was introduced in the U.S. Congress that would restrict or prevent mountaintop mining, although the bill was subsequently defeated.

In order to obtain mining permits and approvals from state regulatory authorities, mine operators must also submit a comprehensive plan for mining and restoring the mined property to its prior condition, productive use or other permitted condition, once mining operations have been completed.  Typically, we submit our permit applications for planned mines promptly upon securing the property rights and required geologic and environmental data.  In our experience, mining permit approvals generally take 12 to 18 months after initial submission; 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.  Significant delays in obtaining, or denial of, permits could have a material adverse effect on our business.

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 deep mining.  SMCRA requires that comprehensive environmental protection and reclamation standards be met during the course of and upon completion of our mining activities.

 

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

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.  In addition, states from time to time have increased and may continue to increase their fees and taxes to fund reclamation or orphaned mine sites and acid mine drainage (“AMD”) control on a statewide basis.

Under SMCRA, responsibility for unabated violations, unpaid civil penalties and unpaid reclamation fees of independent contract mine operators and other third parties can be imputed to other companies that are deemed, according to the regulations, to have “owned” or “controlled” the third-party violator.  Sanctions against the “owner” or “controller” are quite severe and can include being blocked from receiving new permits and having any permits that have been issued since the time of the violations revoked or, in the case of civil penalties and reclamation fees, since the time those amounts became due.  We are not aware of any currently pending or asserted claims against us relating to the “ownership” or “control” theories discussed above.  However, we cannot assure you that such claims will not be asserted in the future.

In November 2009, the U.S. Office of Surface Mining Reclamation (“OSM”) published an Advance Notice of Proposed Rulemaking and announced its intent to revise the Stream Buffer Zone (“SBZ”) rule published in December 2008.  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, 2011 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.  We are unable to predict the impact, if any, of these actions by the OSM, although the actions potentially could result in additional delays and costs associated with obtaining permits, prohibitions or restrictions relating to mining activities near streams, and additional enforcement actions.  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.

 

 

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Bonding Requirements

Federal and state laws require bonds to secure our obligations to reclaim lands used for mining, to pay federal and state workers’ compensation, to pay certain black lung claims, and to satisfy other miscellaneous obligations.  These bonds are typically renewable on a yearly basis.  It has become increasingly difficult for us and for our competitors to secure new surety bonds without posting collateral.  In addition, surety bond costs have increased while the market terms of surety bonds have generally become less favorable to us.  It is possible that surety bond issuers may refuse to renew bonds or may demand additional collateral upon those renewals.  Our failure to maintain, or inability to acquire, surety bonds that are required by state and federal laws would have a material adverse effect on our ability to produce coal, which could affect our profitability and cash flow.

As of December 31, 2012, we had approximately $37.7 million in surety bonds outstanding to secure the performance of our reclamation obligations.

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.  A significant reduction in coal’s share of power generating capacity could have a material adverse effect on our business, financial condition and results of operations.

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

•

The EPA’s Acid Rain Program, provided in Title IV of the CAA, regulates emissions of sulfur dioxide from electric generating facilities. Sulfur dioxide is a by-product of coal combustion.   Affected facilities purchase or are otherwise allocated sulfur dioxide emissions allowances, which must be surrendered annually in an amount equal to a facility’s sulfur dioxide emissions in that year.   Affected facilities may sell or trade excess allowances to other facilities that require additional allowances to offset their sulfur dioxide emissions.   In addition to purchasing or trading for additional sulfur dioxide allowances, affected power facilities can satisfy the requirements of the EPA’s Acid Rain Program by switching to lower sulfur fuels, installing pollution control devices such as flue gas desulfurization systems, or “scrubbers,” or by reducing electricity generating levels.   In 2012, we sold 71.9% of our total tons to electric utilities.

•

The EPA has promulgated rules, referred to as the “Nitrogen Oxide SIP Call,” that, among other things, require coal-fired power plants in 21 eastern states and Washington D.C. to make substantial reductions in nitrogen oxide emissions in an effort to reduce the impacts of ozone transport between states.   As a result of the program, many power plants have been or will be required to install additional emission control measures, such as selective catalytic reduction devices.   Installation of additional emission control measures will make it more costly to operate coal-fired power plants, potentially making coal a less attractive fuel.

 

 

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•

Additionally, in March 2005, the EPA issued the final Clean Air Interstate Rule (“CAIR”) which would have permanently capped nitrogen oxide and sulfur dioxide emissions in 28 eastern states and Washington, D.C.  On July 11, 2008, the D.C. Circuit Court of Appeals vacated CAIR, but on petition for rehearing, the court retracted its decision and remanded the rule to the EPA for further consideration.  This remand had the effect of leaving the rule in place while the EPA evaluated possible changes to the rule to correct the defects identified in the court’s original opinion.  In June 2011, the EPA finalized CSAPR, a replacement rule for CAIR, which requires 28 states in the Midwest and eastern seaboard to reduce power plant emissions that cross state lines and contribute to ozone and/or fine particle pollution in other states.  However, on August 21, 2012, the D.C. Circuit Court of Appeals vacated and remanded the CSAPR rule to the EPA and ordered it to develop a new CAIR replacement in accordance with its 2008 decision.  The court is allowing CAIR to remain in place while a new rule is being developed.  We are unable to predict when the EPA will issue the new rule.

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In March 2005, the EPA finalized the Clean Air Mercury Rule (“CAMR”), which established a two-part, nationwide cap on mercury emissions from coal-fired power plants beginning in 2010.  On February 8, 2008, the D.C. Circuit Court of Appeals vacated CAMR for further consideration by the EPA.  On February 16, 2012, the EPA issued a final rule to establish a national standard to reduce mercury and other toxic air pollutants from coal and oil-fired power plants, referred to as the EPA’s Mercury and Air Toxics Standards (“MATS”).  The EPA granted reconsideration of the rule and proposed updates to the MATS on November 30, 2012.  The EPA also issued a proposed rule requiring Utility Boiler Maximum Achievable Control Technology standards (“Boiler MACT”) for power plants, which would regulate the emission of other air pollutants, including mercury and other metals, fine particulates, and acid gases such as hydrogen chloride for several classes of boilers and process heaters, including large coal-fired boilers and process heaters.  MATS and the Boiler MACT impose stricter limitations on mercury emissions from power plants than the vacated CAMR.  In addition, certain states have adopted or proposed mercury control regulations that are more stringent than the federal requirements.  The Obama Administration has also indicated a desire to negotiate an international treaty to reduce mercury pollution.  More stringent regulation of mercury or other emissions by the EPA, state regulators, Congress, or pursuant to an international treaty may decrease the future demand for coal, but we are unable to predict the magnitude of any such impact with any reasonable degree of certainty.

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The EPA is required by the CAA to periodically re-evaluate the available health effects information to determine whether the national ambient air quality standards (“NAAQS”) should be revised.  Pursuant to this process, the EPA has adopted more stringent NAAQS for fine particulate matter, ozone, nitrogen oxide and sulfur dioxide.  As a result, some states will be required to amend their existing state implementation plans (“SIPs”) to attain and maintain compliance with the new air quality standards and other states will be required to develop new SIPs for areas that were previously in “attainment” but do not attain the new standards.  In addition, under the revised ozone NAAQS, significant additional emissions control expenditures may be required at coal-fired power plants.  Attainment dates for the new standards range between 2013 and 2030, depending on the severity of the non-attainment.  On January 15, 2013, the EPA issued its final rule for fine particulate matter, tightening the standard from 15 micrograms per cubic meter to 12 micrograms per cubic meter.  The rule took effect on March 18, 2013.  In July 2009, the U.S. Court of Appeals for the District of Columbia vacated part of a rule implementing the ozone NAAQS and remanded certain other aspects of the rule to the EPA for further consideration.  Notwithstanding the decision, we expect that additional emissions control requirements may be imposed on new and expanded coal-fired power plants and industrial boilers in the years ahead.  Because coal mining operations and coal-fired electric generating facilities emit particulate matter and nitrogen oxides, which are precursors to ozone formation, our mining operations and our customers could be affected when the new standards are implemented by the applicable states.  We do not know whether or to what extent these developments might indirectly reduce the demand for coal.

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The EPA’s regional haze program is designed to protect and to improve visibility at and around national parks, national wilderness areas and international parks.  On March 30, 2012, the EPA administrator signed a final rule under which the emission caps imposed under CSAPR for a given state would supplant the obligations of that state with regard to visibility protection.  However, the EPA’s plans regarding this rule in light of the stay of CSAPR have yet to be announced.  The regional haze program and any future regulations may restrict the construction of new coal-fired power plants whose operation may impair visibility at and around federally protected areas and may require some existing coal-fired power plants to install additional control measures designed to limit haze-causing emissions.  In addition, the EPA’s new source review program under certain circumstances requires existing coal-fired power plants, when modifications to those plants significantly increase emissions, to install the more stringent air emissions control equipment.  These requirements could limit the demand for coal in some locations.

 

 

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The Department of Justice, on behalf of the EPA, has filed lawsuits against a number of coal-fired electric generating facilities alleging violations of the new source review provisions of the CAA.  The EPA has alleged that certain modifications have been made to these facilities without first obtaining certain permits issued under the new source review program.  Several of these lawsuits have settled, but others remain pending, and still more lawsuits may be filed.  Depending on the ultimate resolution of these cases, demand for coal could be affected.

Climate Change 

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

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

The EPA has also begun regulating greenhouse gas emissions under the 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 greenhouse gas 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 type of source).  The tailoring rule increased this threshold for greenhouse gas emissions to 75,000 tons per year on January 1, 2011 with the intent to tailor the requirement to initially apply only to large stationary sources such as coal-fired power plants and large industrial plants.

Moreover, in October 2009, the EPA issued a final rule requiring certain emitters of greenhouse gases, including coal-fired power plants, to monitor and report their annual greenhouse gas emissions to the EPA beginning in 2011 for emissions occurring in 2010.  Future federal legislative action or judicial decisions to pending or future court challenges may change any of the foregoing final or proposed EPA findings and regulations.  If carbon dioxide emissions from electric utilities were to become subject to additional emission limits or permitting requirements, our customers' demand for coal could decrease.

On March 27, 2012, the EPA proposed new source performance standards for emissions of carbon dioxide for new affected 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 megawatt electric 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 to current levels from 2009 to 2015, followed by a 2.5% reduction each year from 2015 through 2018.  Since its inception, several additional northeastern states and Canadian provinces have joined as participants or observers.  RGGI has been holding quarterly carbon dioxide allowance auctions for its initial three-year compliance period from January 1, 2009 to December 31, 2011 to allow utilities to buy allowances to cover their carbon dioxide emissions.  Other current and proposed greenhouse gas regulation include the Midwestern Greenhouse Gas Reduction Accord, the Western Regional Climate Action Initiative and recently enacted legislation and permit requirements in California and other states.

 

 

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

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

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

Clean Water Act

The Clean Water Act (“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:

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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.  Failures to comply with the CWA or NPDES permits can lead to the imposition of penalties, injunctive relief, compliance costs and delays in coal production.

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

 

 

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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.

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

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

In June 2009, the Corps, EPA and the U.S. Department of the Interior announced an interagency action plan for "Enhanced Coordination" of any project that requires both a SMCRA permit and a CWA permit designed to reduce the harmful environmental consequences of 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, on April 1, 2010, the EPA issued interim final guidance substantially revising the environmental review of CWA permits by state and federal agencies.

In 2010, the National Mining Association (“ 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.).  On July 21, 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.  On October 6, 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.  On July 31, 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.  The decision is currently under appeal with the initial round of briefs due by May 2013.

On June 18, 2010, the Corps announced the suspension of the NWP 21 in the Appalachian regions of Kentucky, Ohio, Pennsylvania, Tennessee, Virginia and West Virginia until the Corps takes further action on NWP 21, or until NWP 21 expired on March 18, 2012.  While the suspension was in effect, proposed surface coal mining projects in these states, including ours, had to obtain individual permits from the Corps pursuant to the CWA.  Projects permitted under NWP 21 were not affected by the suspension, and NWP 21 remained available for proposed surface coal mining projects in other states.

 

 

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On February 21, 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 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.

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 for coal mining 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.

Mine Safety and Health

Stringent safety and health standards have been imposed by federal legislation since 1969 when the Federal Coal Mine Health and Safety Act of 1969 (“CMHSA”) was adopted.  The Federal Mine Safety and Health Act of 1977 (“FMSHA”), and regulations adopted pursuant thereto, significantly expanded the enforcement of health and safety standards of CMHSA, and imposed extensive and detailed safety and health standards on numerous aspects of mining operations, including training of mine personnel, mining procedures, blasting, the equipment used in mining operations, and numerous other matters.  The Mine Safety and Health Administration (“MSHA”) monitors and rigorously enforces compliance with these federal laws and regulations.  In addition, most of the states where we operate also have state programs for mine safety and health regulation and enforcement.  Federal and state safety and health regulations affecting the coal mining industry are perhaps the most comprehensive and rigorous system for protection of employee safety and have a significant effect on our operating costs.  Although many of the requirements primarily impact underground mining, our competitors in all of the areas in which we operate are subject to the same laws and regulations.

 

FMSHA has been construed as authorizing MSHA to issue citations and orders pursuant to the legal doctrine of strict liability, or liability without fault, and FMSHA requires imposition of a civil penalty for each cited violation.  Negligence and gravity assessments, and other factors can result in the issuance of various types of orders, including orders requiring withdrawal from the mine or the affected area, and some orders can also result in the imposition of civil penalties.  FMSHA also contains criminal liability provisions.  For example, criminal liability may be imposed upon corporate operators who knowingly and willfully authorize, order or carry out violations of FMSHA, or its mandatory health and safety standards.

In 2006, the Federal Mine Improvement and New Emergency Response Act of 2006 (“MINER Act”) was enacted.  The MINER Act significantly amended FMSHA, imposing more extensive and stringent compliance standards, increasing criminal penalties and 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 has issued new or more stringent rules and policies on a variety of topics, including:

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sealing off abandoned areas of underground coal mines;

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mine safety equipment, training and emergency reporting requirements;

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substantially increased civil penalties for regulatory violations;

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training and availability of mine rescue teams;

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underground “refuge alternatives” capable of sustaining trapped miners in the event of an emergency;

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flame-resistant conveyor belts, fire prevention and detection, and use of air from the belt entry; and

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post-accident two-way communications and electronic tracking systems.

 

MSHA continues to interpret and implement various provisions of the MINER Act, along with introducing new proposed regulations and standards.  Among these new proposed regulations is MSHA’s proposed rule titled “Lowering Miner’s Exposure to Respirable Coal Mine Dust, Including Continuous Personal Dust Monitors.” The proposed rule would require a 50% reduction in the allowable respirable coal mine dust exposure limits and require each operation to significantly increase the number of respirable coal mine dust samples taken.  The rule would also increase oversight by MSHA regarding coal mine dust and ventilation issues at each mine, including the approval process for ventilation plans at each mine.  Federal legislation was enacted in 2011 to prevent MSHA from implementing or enforcing the proposed rule until such time as the General Accounting Office (“GAO”) performs an independent assessment of MSHA’s data and methodology used in creating the rule.

 

 

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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; and in January 2012, West Virginia began consideration of additional mine safety legislation.  Other states may pass similar legislation in the future.

Some of the costs of complying with existing regulations and implementing new safety and health regulations may be passed on to our customers.  Although we are unable to quantify the full impact, implementing and complying with these new state and federal safety laws and regulations have had, and are expected to continue to have, an adverse impact on our results of operations and financial position.

In 2010, in response to additional underground mine accidents, Congress expanded mine safety disclosure requirements pursuant to Section 1503 of the Dodd-Frank Wall Street Reform and Consumer Act.  On December 21, 2011, the SEC issued final rules implementing Section 1503, outlining the way in which mining companies must disclose to investors certain information about mine safety and health standards.  These new SEC rules were adopted as final in December 2011, and became effective on January 27, 2012.  The new rules 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.  Our disclosure in this regard can be found in "Exhibit 95, Mine Safety Disclosure."

 

Black Lung Benefits Act

The Federal Black Lung Benefits Act (“BLBA”) requires businesses that conduct current mining operations to make payments of black lung benefits to coal miners with black lung disease and to some survivors of a miner who dies from this disease.  The BLBA levies an excise tax on production of $0.55 per ton for surface-mined coal, but not to exceed 4.4% of the applicable sales price, in order to compensate miners who are totally disabled due to black lung disease and some survivors of miners who died from this disease, and who were last employed as miners prior to 1970 or subsequently where no responsible coal mine operator has been identified for claims.  In addition, BLBA provides that some claims for which coal operators had previously been responsible are or will become obligations of the government trust funded by the tax.  The Revenue Act of 1987 extended the termination date of this tax from January 1, 1996, to the earlier of January 1, 2014, or the date on which the government trust becomes solvent.  We are also liable under state statutes for black lung claims.  Congress and state legislatures regularly consider various items of black lung legislation, which, if enacted, could adversely affect our business, results of operations and financial position.   In 2012, we recognized $3.6 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 on March 23, 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.

 

 

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 Comprehensive Environmental Response, Compensation and Liability Act

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

 

Resource Conservation and Recovery Act

The Federal Resource Conservation and Recovery Act (“RCRA”) and corresponding state laws regulating hazardous waste affect coal mining operations by imposing requirements for the generation, transportation, treatment, storage, disposal, and cleanup of hazardous wastes.  Many mining wastes are excluded from the regulatory definition of hazardous wastes, and coal mining operations covered by SMCRA permits are by statute exempted from RCRA permitting.  RCRA also allows the EPA to require corrective action at sites where there is a release of hazardous substances.  In addition, each state has its own laws regarding the proper management and disposal of waste material.  While these laws impose ongoing compliance obligations, such costs are not believed to have a material impact on our operations.

On June 21, 2010, the EPA released a proposed rule to regulate the disposal of certain coal combustion by-products (“CCB”).  The rule sets forth two very different approaches for regulating CCB under RCRA.  The first option calls for regulation of CCB as a hazardous waste under Subtitle C, which creates a comprehensive program of federally enforceable requirements for waste management and disposal.  The second option utilizes Subtitle D, which gives the EPA authority to set performance standards for waste management facilities and would be enforced primarily through citizen suits.  The proposal leaves intact the Bevill exemption for beneficial uses of CCB.  If CCB is not classified as hazardous waste, it is not anticipated that regulation of CCB will have any material effect on the amount of coal used by electricity generators.  However, if CCB were re-classified as hazardous waste, regulations would likely restrict ash disposal, provide specifications for storage facilities, require groundwater testing and impose restrictions on storage locations, which could increase our customers’ operating costs and potentially reduce their ability to purchase coal.  In addition, contamination caused by the past disposal of CCB, including coal ash, may lead to material liability to our customers under RCRA or other federal or state laws and potentially reduce the demand for coal.  Although it is not currently possible to predict how such regulations would impact our operations or those of our customers, the regulation of CCB as hazardous waste could result in increased disposal and compliance costs, which could result in decreased demand for our products.

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.  In addition, our use of explosives is subject to the Federal Safe Explosives Act.  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.  The costs of compliance with these regulations should not have a material adverse effect on our business, financial condition or results of operations.

 

 

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Employees

To conduct our operations, as of December 31, 2012, we employed 758 full-time employees, including 581 employees involved in active mining operations, 143 employees in other operations, and 34 corporate employees.  Our workforce is entirely union-free.   We believe that we have good relations with these employees, and we continually seek their input with respect to our operations.  Since our inception, we have had no history of work stoppages or union organizing campaigns.

Additional Information

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

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

GLOSSARY OF SELECTED TERMS

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

Bituminous coal : A middle rank coal (between sub-bituminous and anthracite) 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 10,000 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 changed 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 at the front end for moving earth, rocks, etc.

 

 

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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.

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

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

Limestone : A rock predominantly composed of the mineral calcite (calcium carbonate (“CaCO2”)).

Metallurgical coal :  The various grades of coal suitable for carbonization to make coke for steel manufacture.  Its quality depends on four important criteria: volatility, which affects coke yield; the level of impurities including sulfur and ash, which affects coke quality; composition, which affects coke strength; and basic characteristics, which affect coke oven safety.  Metallurgical coal typically has a particularly high Btu, but low ash and sulfur content.

Nitrogen oxide (NOx): A gas formed in high temperature environments, such as coal combustion.  It is a harmful pollutant that 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.  In surface mining operations, overburden is removed prior to coal extraction.

Preparation plant : Usually located on a mine site, although one plant may serve several mines.  A preparation plant is 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.

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 recovered from the Reserves.  The recovery factor for surface mines is typically 80% to 90%.

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

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).

 

 

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

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

Sulfur : One of the elements present in varying quantities in coal that 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.

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

Our independent registered public accounting firm has included an emphasis paragraph with respect to our ability to continue as a going concern in its report on our consolidated financial statements for the year ended December 31, 2012.

As discussed in “Part I, Item 1, Business —Going Concern Considerations,” and "Part II, Item 7 - Management's Discussion and Analysis of Financial Condition and Results of Operations—Recent Developments – Credit Facility, " the uncertainty regarding the future of our existing credit facility has created substantial doubt about our ability to continue as a going concern.  As a consequence, our auditors have included an emphasis paragraph with respect to this issue in their report on our consolidated financial statements as of and for the year ended December 31, 2012 included in this Annual Report on Form 10-K (our “consolidated 2012 financial statements”).  Our consolidated 2012 financial statements have been prepared assuming that we will continue as a going concern.  All amounts outstanding under the revolving credit line portion of our existing credit facility have been classified as current liabilities in our consolidated balance sheet as of December 31, 2012.   While our consolidated 2012 financial statements reflect significant asset impairment expenses for the year ended December 31, 2012, they do not include any adjustments relating to the recoverability and classification of asset carrying amounts or the amount of and classification of liabilities that may result should we be unable to continue as a going concern.   The presence of the going concern emphasis paragraph in our auditors’ report may have an adverse impact on our relationship with third parties with whom we do business, including our customers, vendors, lenders and employees, making it difficult to raise additional debt or equity financing to the extent needed.  As a result, our business, results of operations, financial condition and prospects could be materially adversely affected.

Our management has been actively working and will continue to work with the lenders to amend the provisions and extend the term of our existing credit facility.  However, there can be no assurance that we will be successful in amending and extending the facility.  Therefore, there can be no guarantee that our existing sources of cash and our future cash flows from operations will be adequate to meet our liquidity requirements, including cash requirements that are due under our existing credit facility or that are needed to fund our business operations.  If we are unable to address our liquidity challenges, then our business and operating results could be materially adversely affected, potentially resulting in the need to curtail our business operations and/or reorganize our capital structure.

In the event that we are unable to achieve an acceptable negotiated restructuring of our indebtedness, we may be forced to seek reorganization under the U.S. Bankruptcy Code.

We are engaged in continuing discussions with the lenders for our existing credit facility to amend the provisions and extend the term of such credit facility .  In the event that we are unable to amend and extend our existing credit facility on acceptable terms, we may be forced to seek some form of restructuring.  There can be no assurance that either an agreement regarding amendment and extension of our existing credit facility or an agreement regarding any such restructuring will be obtained on acceptable terms or at all.  If such an acceptable agreement is not obtained in a timely manner, we will be in default under our existing credit facility at some time before or when it matures in July 2013 and our lenders will be entitled to accelerate all of our obligations under such credit facility.  In addition, any such default under our existing credit facility could result in a cross-default or the acceleration of our payment obligations under other financing agreements.  In any such event, we may be required to seek a reorganization under court supervision pursuant to a voluntary bankruptcy filing under Chapter 11 of the U.S. Bankruptcy Code.

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

In order to pay the minimum quarterly distribution of $0.4375 per unit per quarter, or $1.75 per unit per year, we will require available cash of more than $9.3 million per quarter, or $37.0 million per year, based on the number of general partner units, common units and subordinated units outstanding at December 31, 2012.  We may not have sufficient cash each quarter to pay the minimum quarterly distribution.  The amount of cash we can distribute on our units principally depends upon the amount of cash we generate from our operations, which will fluctuate from quarter to quarter based on, among other things:

•

the amount of coal we are able to produce from our properties;

 

 

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the price at which we are able to sell coal, which is affected by the supply of and demand for domestic and foreign coal;

•

the level of our operating costs;

•

weather conditions;

•

the proximity to and capacity of transportation facilities;

•

domestic and foreign governmental regulations and taxes;

•

the price and availability of alternative fuels;

•

the effect of world-wide energy consumption; and

•

prevailing economic conditions.

In addition, the actual amount of cash available for distribution will depend on other factors, including:

•

the level of our capital expenditures;

•

the cost of acquisitions, if any;

•

our debt service requirements and restrictions on distributions contained in our current or future debt agreements;

•

fluctuations in our working capital needs;

•

unavailability of financing resulting in unanticipated liquidity restraints; and

•

the amount, if any, of cash reserves established by our managing general partner, in its discretion, for the proper conduct of our business.

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

In January 2013, we determined to suspend the cash distributions on both our common and subordinated units based upon 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, 2012, the accumulated arrearage amounts totaled $2.5 million.

 

 

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Any change in consumption patterns by utilities away from the use of coal, such as resulting from current low natural gas prices, could affect our ability to sell the coal we produce, which could adversely affect our results of operations and cash available for distribution to our unitholders.

Steam coal accounted for approximately 100% of our coal sales volume for the year ended December 31, 2012.  During this period, 71.7% of our sales of steam coal 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.  We compete generally with producers of other fuels, such as natural gas and oil.  A decline in price for these fuels 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 benefit 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.  A decrease in coal consumption by the domestic electric utility industry could adversely affect the price of coal, which could materially adversely affect our results of operations and cash available for distribution to our unitholders.

We depend on a few customers for a significant portion of our revenues.  If a substantial portion of our supply contracts terminate or if any of these customers were to significantly reduce their purchases of coal from us, and we are unable to successfully renegotiate or replace these contracts on comparable terms, then our results of operations and cash available for distribution to our unitholders could be adversely affected.

We sell a material portion of our coal under supply contracts.  As of December 31, 2012 we had sales commitments for approximately 97.9% of our estimated coal production (including purchased coal to supplement our production) for the year ending December 31, 2013.  When our current contracts with customers expire, our customers may decide not to extend or enter into new contracts.  Of these committed tons, under the terms of the supply contracts, we are committed to ship 6.5 million tons in 2013, 5.2 million tons in 2014, 4.4 million tons in 2015 and 2.5 million tons in 2016.  Some of the contracts amounting to 2.1 million, 4.2 million, and 2.5 million tons of coal in 2014, 2015 and 2016, respectively, have sales price adjustment provisions, subject to certain limitations and adjustments, based on a variety of factors and indices.  We derived approximately 93.3% of our total revenues from coal sales to our ten largest customers for the year ended December 31, 2012, with affiliates of our top three customers accounting for approximately 72.6% of our coal sales revenues during that period.

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, and those customers may not continue to purchase coal from us under long-term coal supply contracts or may significantly reduce their purchases of coal from us.  In addition, interruption in the purchases by or operations of our principal customers could significantly affect our results of operations and cash available for distribution.  Unscheduled maintenance outages at our customers' power plants and unseasonably moderate weather are examples of conditions that might cause our customers to reduce their purchases.  Our mines may have difficulty identifying alternative purchasers of their coal if their existing customers suspend or terminate their purchases.

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

A decline in coal prices could adversely affect our results of operations and cash available for distribution to our unitholders.

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 in any case where the pricing under such contracts is tied to and adjusted periodically based on indices reflecting current market pricing;

 

 

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•

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, climatic 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;

•

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 weaker demand and lower prices for our products.  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 electrical 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 for our coal supply contracts could materially and adversely affect our results of operations.

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

Numerous governmental permits and approvals are required for mining operations, and we can face delays, 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 discharge dredged or fill material into waters of the United States.  Our surface coal mining operations typically require such permits to authorize such activities as the creation of slurry ponds, stream impoundments, and valley fills.  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.

Please read "Part I, Item 1. Business - Environmental, Safety and Other Regulatory Matters — Clean Water Act " for a discussion of recent litigation and regulatory developments related to the CWA.  An inability to obtain the necessary permits to conduct our mining operations or an inability to comply with the requirements of applicable permits would reduce our production and cash flows, which could limit our ability to make distributions to our unitholders.

 

 

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Certain provisions in our long-term supply contracts may provide limited protection during adverse economic conditions, may result in economic penalties to us or permit the customer to terminate the contract.

Price adjustment, "price 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 results of operations and cash available for distribution to our unitholders.

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.

If we are not able to acquire replacement coal reserves that are economically recoverable, our results of operations and cash available for distribution to our unitholders could be adversely affected.

Our results of operations and cash available for distribution to our unitholders 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.  We may not be able to accurately assess the geological characteristics of any reserves that we acquire, which may adversely affect our results of operations and cash available for distribution to our unitholders.  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 or future debt agreements.

We could be negatively impacted by the competitiveness of the markets in which we compete and declines in the market demand for coal.

We compete with coal producers in the 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.  Consumption by the domestic electric utility industry is affected by the demand for electricity, environmental and other governmental regulations, technological developments and the price of competing coal and alternative fuel sources, such as natural gas, nuclear, hydroelectric power and other renewable energy sources.  In 2012 the EIA estimates that coal consumption in the electric power sector totaled 829 million tons, the lowest amount since 1992 due to historically 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.  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 impacting our results of operations and cash available for distribution.

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

Recent scientific studies have suggested that emissions of certain gases, commonly referred to as greenhouse gases and including carbon dioxide and methane, may be contributing to warming of the Earth's atmosphere 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 of GHG, primarily through the development of regional GHG cap-and-trade programs.

 

 

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In the wake of the Supreme Court's April 2, 2007 decision in Massachusetts, et al. v. EPA , which held that GHG fall under the definition of "air pollutant" in the CAA, in December 2009 the EPA issued a final rule declaring that six GHG, 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 GHG, including possible future U.S. treaty commitments, new federal or state legislation that may impose a carbon emissions tax or establish a cap-and-trade program and regulation by the EPA.

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 requirements 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 results of operations and cash available for distribution to our unitholders.  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 the demand for our coal.  A reduction in demand for our coal could adversely affect our results of operations and cash available for distribution to our unitholders.

Federal, state and local laws and regulations extensively regulate the amount of sulfur dioxide, particulate matter, nitrogen oxides, mercury and other compounds emitted into the air from electric power plants and other consumers of our coal.  These laws and regulations can require significant emission control expenditures, and various new and proposed laws and regulations may require further emission reductions and associated emission control expenditures.  A certain portion of our coal has a medium to high sulfur content, which results in increased sulfur dioxide emissions when combusted and therefore the use of our coal imposes certain additional costs on customers.  Accordingly, these laws and regulations may affect demand and prices for our higher sulfur coal.  Please read "Part I, Item 1 - Business — Environmental, Safety and Other Regulatory Matters — Air Emissions .”

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

Our 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;

•

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

 

 

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•

accidents, including fire and explosions from methane.

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

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 workmen's 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 shut-down 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 results of operations and cash available for distribution.
 

Federal or state regulatory agencies have the authority to order certain of our mines to be temporarily or permanently closed under certain circumstances, which could materially and adversely affect our ability to meet our customers’ demands.

Federal or state regulatory agencies have the authority under certain circumstances following significant health and safety incidents, such as fatalities, to order a mine to be temporarily or permanently closed.  If this occurred, we may be required to incur capital expenditures to re-open the mine.  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, to fulfill these obligations, incur capital expenditures to re-open the mines and/or negotiate settlements with the customers, which may include price reductions, the reduction of commitments, the extension of time for delivery or the termination of customers’ contracts.  Any of these actions could have a material adverse effect on our business and results of operations.

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

In January 2007, we entered into a joint venture, Harrison Resources, with CONSOL Energy.  Pursuant to its operating agreement, all members of Harrison Resources must approve cash distributions, other than tax distributions, to its members.  Prior to 2012, the members of Harrison Resources have consistently approved cash distributions from Harrison Resources on a quarterly basis.  In 2012, the members of Harrison Resources did not approve a cash distribution as it was necessary to reserve cash to pay coal reserves acquisition costs.  It is expected that it will be necessary to continue to reserve cash for such purpose rather than paying a cash distribution during all of 2013 and some or all of 2014, and for that reason and otherwise there can be no assurance that we will receive regular cash distributions from Harrison Resources in the future.

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

 

 

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Our partnership agreement requires that we distribute all of our available cash, which could limit our ability to grow and make acquisitions.

We expect that we will distribute all of our available cash to our unitholders and will rely primarily upon external financing sources, including commercial bank borrowings and the issuance of debt and equity securities, to fund our acquisitions and expansion capital expenditures.  As a result, to the extent we are unable to finance growth externally, our cash distribution policy will significantly impair our ability to grow.  For discussion of our recent suspension of cash distributions, see the risk factor entitled: “ We may not have sufficient cash to enable us to pay the minimum quarterly distribution on our common units, subordinated units and general partner units following the establishment of cash reserves by our general partner and the payment of costs and expenses, including reimbursement of expenses to our general partner .”

In addition, because we distribute all of our available cash, our growth may not be as fast as that of businesses that reinvest their available cash to expand ongoing operations.  To the extent we issue additional units in connection with any acquisitions or expansion capital expenditures, the payment of distributions on those additional units may increase the risk that we will be unable to maintain or increase our per unit distribution level.  There are no limitations in our partnership agreement or our credit agreement on our ability to issue additional units, including units ranking senior to the common units.  The incurrence of additional commercial borrowings or other debt to finance our growth strategy would result in increased interest expense, which, in turn, may impact the available cash that we have to distribute to our unitholders.

Unexpected increases in raw material costs, such as steel, diesel fuel and explosives, could adversely affect our results of operations.

Our coal mining operations are affected by commodity prices.  We use significant amounts of steel, diesel fuel, explosives and other raw materials in our mining operations, and volatility in the prices for these raw materials could have a material adverse effect on our operations.  Steel prices and the prices of scrap steel, natural gas and coking coal consumed in the production of iron and steel fluctuate significantly and may change 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 price of steel, diesel fuel, explosives or other raw materials will impact our operating expenses and could adversely affect our results of operations and cash available for distribution.

Fluctuations in transportation costs or disruptions in transportation services could increase competition or impair our ability to supply coal to our customers, which could adversely affect our results of operations and cash available for distribution to our unitholders.

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 supply coal to our customers.  As we do not have long-term contracts with transportation providers to ensure consistent and reliable service, decreased performance levels over longer 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.

In recent years, the Commonwealth of Kentucky and the State of West Virginia have increased enforcement of weight limits on coal trucks on their public roads.  It is possible that all states in which our coal is transported by truck may modify their laws to limit truck weight limits.  Such legislation and enforcement efforts could result in shipment delays and increased costs.  An increase in transportation costs could have an adverse effect on our ability to increase or to maintain production and could adversely affect revenues.

If we experience disruptions in our transportation services or if transportation costs increase significantly and we are unable to find alternative transportation providers, our coal mining operations may be disrupted, could experience a delay or halt of production, or profitability could decrease significantly.

 

 

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Our 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 and time-consuming and may delay commencement or continuation of our operations.  Moreover, the possibility exists that new laws or regulations (or new judicial interpretations or enforcement policies of existing laws and regulations) could materially affect our mining operations, results of operations and cash available for distribution to our unitholders, 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.  The enforcement of laws and regulations governing the coal mining industry has increased substantially.  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 applicable environmental laws and have the potential to generate other materials, all of which may affect runoff or drainage water.  In the event of environmental contamination or a release of these materials, 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.

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, which could affect our mining operations and cost structures in these areas.

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 have a material adverse effect on the mining operations and cost structures of our mines in Northern Appalachia and the Illinois Basin.

If the assumptions underlying our reclamation and mine closure obligations are materially inaccurate, we could be required to expend greater amounts than anticipated.

The Federal Surface Mining Control and Reclamation Act of 1977 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.  The estimate of ultimate reclamation liability is reviewed periodically by our management.  The estimated liability can change significantly if actual costs vary from assumptions or if governmental regulations change significantly.  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. "

The amount of estimated maintenance capital expenditures that we are required to deduct from operating surplus each quarter could increase in the future, resulting in a decrease in available cash from operating surplus that we could distribute to our unitholders.

Maintenance capital   expenditures that we are required to deduct from operating surplus each quarter could increase in the future, resulting in a decrease in available cash from operating surplus that we could distribute to our unitholders.

 

 

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Our partnership agreement requires us to deduct from operating surplus each quarter estimated maintenance capital expenditures as opposed to actual maintenance capital expenditures in order to reduce disparities in operating surplus caused by fluctuating maintenance capital expenditures, such as reserve replacement costs or refurbishment or replacement of mine equipment.  Our annual estimated maintenance capital expenditures for purposes of calculating operating surplus are $22.0 million to $25.0 million for 2013.  The estimated maintenance capital expenditures are based on our current estimates of the amounts of expenditures we will be required to make in the future to maintain our long-term operating capacity, which we believe to be reasonable.  Our partnership agreement does not cap the amount of maintenance capital expenditures that we may estimate.  The amount of our estimated maintenance capital expenditures may be more than our actual maintenance capital expenditures, which will reduce the amount of available cash from operating surplus that we would otherwise have available for distribution to unitholders.

Our 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;

•

covenants contained in our existing and future credit and debt arrangements will require us to meet financial tests that may affect our flexibility in planning for and reacting to changes in our business, including possible acquisition opportunities;

•

we will need a portion of our cash flow to make principal and interest payments on our indebtedness, reducing the funds that would otherwise be available for operations, distributions to unitholders and future business opportunities;

•

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

•

our flexibility in responding to changing business and economic conditions.

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

Our credit agreement contains operating and financial restrictions that may restrict our business and financing activities and limit our ability to pay distributions upon the occurrence of certain events.

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

•

incur additional debt;

•

make distributions on or redeem or repurchase units;

•

make certain investments and acquisitions;

•

incur certain liens or permit them to exist;

•

enter into certain types of transactions with affiliates;

•

merge or consolidate with another company; and

•

transfer or otherwise dispose of assets.

 

 

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

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

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

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

We depend on the services of our senior management team and other key personnel.  The loss of the services of any member of senior management or key employee could have an adverse effect on our business and reduce our ability to make distributions to our unitholders.  We may not be able to locate or employ on acceptable terms qualified replacements for senior management or other key employees if their services were no longer available.
 

A shortage of skilled labor in the mining industry could reduce productivity and increase operating costs, which could adversely affect our results of operations and cash available for distribution to our unitholders.
 

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 retire 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 coal prices decrease or our labor prices increase, our results of operations and cash available for distribution to our unitholders could be adversely affected.

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

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.

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

We base our and the joint venture's coal reserve and non-reserve coal deposit estimates on engineering, economic and geological data assembled and analyzed by our staff, which 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 relate to:

•

quality of the coal;

 

 

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•

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

•

the percentage of coal ultimately recoverable;

•

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

•

assumptions concerning the timing for the development of reserves; and

•

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

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

Our lessees' mining operations and their financial condition and results of operations are subject to some of the same risks and uncertainties that we face as a mine operator.

The mining operations and financial condition and results of operations of our lessees are subject to the same risks and uncertainties that we face as a mine operator.  If any such risks were to occur, the business, financial condition and results of operations of the lessees could be adversely affected and as a result our coal royalty revenues and cash available for distribution could be adversely affected.

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

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

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

In addition, we sell some of our mined coal to coal brokers who may resell our coal to end users, including utilities.  These coal brokers may have only limited assets, making them less creditworthy than the end users.  Under some of these arrangements, we have contractual privity only with the brokers and may not be able to pursue claims against the end users in connection with these sales if we do not receive payment from the broker.  In 2012, approximately 38.0% of our coal sales were through coal brokers.  We expect our coal sales through coal brokers to increase to approximately 40.8% of our sales in 2013.

 

 

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Federal and state laws require bonds to secure our obligations to reclaim mined property.  Our inability to acquire or failure to maintain, obtain or renew these surety bonds could have an adverse effect on our ability to produce coal, which could adversely affect our results of operations and cash available for distribution to our unitholders.

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 miscellaneous obligations.  Federal and state governments could increase bonding requirements in the future.  Certain business transactions, such as coal leases and other obligations, may also require bonding.  We may have difficulty procuring or maintaining our surety bonds.  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.  Such failure could result from a variety of factors, including:

•

the lack of availability, higher expense or unreasonable terms of new surety bonds;

•

the ability of current and future surety bond issuers to increase required collateral; and

•

the exercise by third-party surety bond holders of their right to refuse to renew the surety bonds.

We maintain surety bonds with third parties for reclamation expenses and other miscellaneous obligations.  It is possible that we may in the future have difficulty maintaining our surety bonds for mine reclamation.  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 have greater difficulty satisfying the liquidity requirements under our existing surety bond contracts.  As of December 31, 2012, we had $37.7 million in reclamation surety bonds, secured by $8.9 million in letters of credit outstanding under our credit agreement.  Our credit agreement provides for a $115.0 million working capital revolving credit facility, of which up to $20.0 million may be used for letters of credit.  If we do not maintain sufficient borrowing capacity under our revolving credit facility for additional letters of credit, we may be unable to obtain or renew surety bonds required for our mining operations.  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 Facility. " If we do not maintain sufficient borrowing capacity or have other resources to satisfy our surety and bonding requirements, our operations and cash available for distribution to our unitholders could be adversely affected.

Defects in title in 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 materially adversely affected by actual or alleged defects in title or boundaries.  In order to obtain leases or mining contracts to conduct our mining operations on property where these defects exist, we may in the future have to incur unanticipated costs or could even lose our right to mine on that property, which could adversely affect our profitability.  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.

The amount of estimated reserve replacement expenditures that we are required to deduct from operating surplus each quarter is based on our current estimates and could increase in the future, resulting in a decrease in available cash from operating surplus that could be distributed to our unitholders.

Reserve replacements are acquired through direct acquisition or lease.  For 2013, we expect to enter into various leases to replace reserves mined in 2013, as leasing reserves allows us to better align our cash outflows with cash inflows from operations.  We do not expect to incur reserve replacement direct acquisition expenditures.  Our partnership agreement requires us to deduct from operating surplus each quarter estimated reserve replacement expenditures as opposed to actual reserve replacement expenditures in order to reduce disparities in operating surplus caused by fluctuating reserve replacement costs.  This amount is based on our current estimates of the amounts of expenditures will be required to make in future years to maintain our depleting reserve base, which we believe to be reasonable.  In the future, estimated reserve replacement expenditures may be more than our actual reserve replacement expenditures, which will reduce the amount of available cash from operating surplus that we would otherwise have available for distribution to unitholders.  The amount of estimated reserve replacement expenditures deducted from operating surplus is subject to review and change by the board of directors of our general partner at least once a year, subject to approval by the audit committee of the board of directors of our general partner, acting in its capacity as a conflicts committee .

 

 

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Our hedging activities for diesel fuel may prevent us from benefiting from price decreases.

We enter into forward contract arrangements for a portion of our anticipated diesel fuel and explosive needs.  As of December 31, 2012, we had fixed-price fuel contracts for approximately 56.3% of our calendar year 2013 expected diesel fuel needs.  Additionally we are protected 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.  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 contracts, we would lose the benefit of any such decrease.

The government extensively regulates mining operations, especially with respect to mine safety and health, which imposes significant actual and potential costs on us, and future regulation could increase those 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 in the United States in recent years have received national attention and have led to responses at the state and federal levels that have resulted in increased regulatory scrutiny of coal mining operations, particularly underground mining operations.  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, or 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 information reporting requirements.  The MINER Act significantly amended the Federal Mine Safety and Health Act of 1977, or the Mine Act, imposing more extensive and stringent compliance standards, increasing criminal penalties and 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, the U.S. Mine Safety and Health Administration, or 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.

Subsequent to passage of the MINER Act, 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, particularly with respect to underground mining operations, is being considered.

MSHA is also considering a new rule regarding respirable coal mine 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 (“CPDM”), 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 full impact, implementing and complying with these new laws and regulations could have an adverse impact on our results of operations and cash available for distribution to our unitholders and could result in harsher sanctions in the event of any violations.  Please read "Part I, Item 1 - Business—Environmental, Safety and Other Regulatory Matters. "

 

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Risks Inherent in an Investment in Us

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

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

•

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 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 18.1% limited partner interest in us, AIM Oxford owns a 35.5% limited partner interest in us, and C&T Coal and AIM Oxford own substantially all of and control our general partner and its 2.0% general partner interest in us.  Although our general partner has certain fiduciary duties to manage us in a manner beneficial to us and our unitholders, the executive officers and directors of our general partner have a fiduciary duty to manage our general partner in a manner beneficial to its owners.  Furthermore, since certain executive officers and directors of our general partner are executive officers or directors of affiliates of our general partner, conflicts of interest may arise between C&T Coal and AIM Oxford and their affiliates, including our general partner, on the one hand, and us and our unitholders, on the other hand.  As a result of these conflicts, our general partner may favor its own interests and the interests of its affiliates over the interests of our unitholders.  Please read “— Our partnership agreement limits our general partner’s fiduciary duties to our unitholders and restricts the remedies available to our unitholders for actions taken by our general partner that might otherwise constitute breaches of fiduciary duties.”  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 the amount of cash that is available for distribution to our unitholders;

•

our general partner determines our estimated reserve replacement expenditures, which reduce operating surplus, and that determination can affect the amount of cash that is distributed to our unitholders and the ability of the subordinated units to convert to common units;

•

in some instances, our general partner may cause us to borrow funds in order to permit the payment of cash distributions, even if the purpose or effect of the borrowing is to make a distribution on the subordinated units, to make incentive distributions or to accelerate the expiration of the subordination periods;

•

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

•

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;

•

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.

 

 

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

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

Our unitholders are unable to remove our general partner without its consent because affiliates of our general partner own sufficient units to be able to prevent removal of our general partner.  The vote of the holders of at least 80% 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 54.6% of our common units and subordinated units.   Also, if our general partner is removed without cause during the subordination period and units held by our general partner and its affiliates are not voted in favor of that removal, all remaining subordinated units will automatically be converted into common units and any existing arrearages on the common units will be extinguished.  A removal of our general partner under these circumstances would adversely affect the common units by prematurely eliminating their distribution and liquidation preference over the subordinated units, which would otherwise have continued until we had met certain distribution and performance tests.

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

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

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

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

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

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

C&T Coal and AIM Oxford own an aggregate of 54.6% of our common units and subordinated units.  If at any time our general partner and its affiliates own more than 80.0% of the common units, our general partner will have the right, but not the obligation, which it may assign to any of its affiliates or to us, to acquire all, but not less than all, of the common units held by unaffiliated persons at a price not less than the then-current market price.  As a result, our unitholders may be required to sell their common units at an undesirable time or price and may not receive any return on their investment.  Our unitholders may also incur a tax liability upon a sale of their common units.  Our general partner is not obligated to obtain a fairness opinion regarding the value of the common units to be repurchased by it upon exercise of the limited call right.  There is no restriction in our partnership agreement that prevents our general partner from issuing additional common units and exercising its limited call right.  If our general partner exercised its limited call right, the effect would be to take us private and, if the common units were subsequently deregistered, we would no longer be subject to the reporting requirements of the Exchange Act.

 

 

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

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

•

our unitholders’ proportionate ownership interest in us will decrease;

•

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

•

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

•

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

•

the market price of the common units may decline.

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

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

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

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

As of December 31, 2012, a single unaffiliated unitholder owned 1,198,175, or 11.4%, of our common units.  That unitholder may sell some or all of these units 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.

 

 

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

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

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

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

Our unitholders may have liability to repay distributions.

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

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.  If the Internal Revenue Service, or the IRS, were to treat us as a corporation for federal income tax purposes, which would subject us to entity-level taxation, then our cash available for distribution to our unitholders would be substantially reduced.

The anticipated after-tax economic benefit of an investment in 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 you.  Because a tax would be imposed upon us as a corporation, our cash available for distribution to you would be substantially reduced.  Therefore, if we were treated as a corporation for federal income tax purposes there would be material reduction in the anticipated cash flow and after-tax return to our unitholders, likely causing a substantial reduction in the value of our common units.

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

If we were subjected to a material amount of additional entity-level taxation by individual states, it would reduce our cash available for distribution to our unitholders.

Changes in current state law may subject us to additional entity-level taxation by individual states.  Because of widespread state budget deficits and other reasons, several states are evaluating ways to subject partnerships to entity-level taxation through the imposition of state income, franchise and other forms of taxation.  Imposition of any such taxes may substantially reduce the cash available for distribution to you.

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

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

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

 

 

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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 Budget Proposal for Fiscal Year 2013, or the Budget Proposal, is the elimination of certain key U.S. federal income tax preferences relating to coal exploration and development.  The Budget Proposal would: (i) eliminate current deductions, the 60-month amortization period and the 10-year amortization period for exploration and development costs relating to coal and other hard mineral fossil fuels, (ii) repeal the percentage depletion allowance with respect to coal properties, (iii) repeal capital gains treatment of coal and lignite royalties and (iv) exclude from the definition of domestic production gross receipts all gross receipts derived from the production of coal and other hard mineral fossil fuels.  The passage of any legislation as a result of the Budget Proposal or any other similar changes in U.S. federal income tax laws could eliminate certain tax deductions that are currently available with respect to coal exploration and development, and any such change could increase the taxable income allocable to our unitholders and negatively impact the value of an investment in our common units.

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

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

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

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

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

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

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

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

 

 

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

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

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

We prorate our items of income, gain, loss and deduction for U.S. federal income tax purposes between transferors and transferees of our units each month based upon the ownership of our units on the first day of each month, instead of on the basis of the date a particular unit is transferred.  The use of this proration method may not be permitted under existing Treasury Regulations.  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.  If so, he would no longer be treated for federal income tax purposes as a partner with respect to those common units during the period of the loan and may recognize gain or loss from the disposition.

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

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

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

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

 

 

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

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

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

In addition to federal income taxes, our unitholders will likely be subject to other taxes, including state and local taxes, unincorporated business taxes and estate, inheritance or intangible taxes that are imposed by the various jurisdictions in which we conduct business or control property now or in the future, even if they do not live in any of those jurisdictions.  Our unitholders will likely be required to file state and local income tax returns and pay state and local income taxes in some or all of these various jurisdictions.  Further, our unitholders may be subject to penalties for failure to comply with those requirements.  We conduct business in Indiana, Kentucky, Ohio 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 your responsibility to file all U.S. federal, state and local tax returns.  Our counsel has not rendered an opinion on the state or local tax consequences of an investment in our common units.

 

ITEM 1B.             UNRESOLVED STAFF COMMENTS

None.

ITEM 2.                 PROPERTIES

Mining Operations

See “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 the 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.  We maintain coal reserve information in secure computerized databases, as well as in hard copy.  The ability to update and/or modify the estimates of our coal reserves is restricted to a few individuals and the modifications are documented.

 

 

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Periodically, we retain outside experts to independently verify our coal reserve and our non-reserve coal deposit estimates.  At December 31, 2012, an audit 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, 2012, we owned 17.3% of our coal reserves and leased 82.7% of our coal reserves from various third-party landowners.   As of December 31, 2012, we controlled an estimated 86.4 million tons of proven and probable reserves.

The following table provides information as of December 31, 2012 on the location of our operations and the amount and ownership of our coal reserves:

 

		Total Tons of Proven and Probable Coal Reserves
Mining Complex		Total				Owned				Leased
		(in thousands tons)
Surface Mining Operations:
Northern Appalachia (principally Ohio)
Cadiz			8,437				4,390				4,047
Tuscarawas County			8,636				82				8,554
Plainfield			2,771				737				2,034
Belmont County			12,956				4,411				8,545
New Lexington			3,687				1,839				1,848
Harrison (1)			3,471				3,471				-
Noble County			2,741				-				2,741
Total Northern Appalachia			42,699				14,930				27,769
Illinois Basin (Kentucky)
Muhlenberg County			19,399				-				19,399
Total Illinois Basin			19,399				-				19,399
Total Surface Mining Operations			62,098				14,930				47,168
Underground Coal Reserves:
Tusky			24,343				-				24,343
Total Underground Coal Reserves			24,343				-				24,343
Total			86,441				14,930				71,511
Percentage of Total			100.0	%			17.3	%			82.7	%

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(1)

The Harrison mining complex is owned by Harrison Resources.  We own 51% of Harrison Resources and CONSOL Energy Inc. 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, 2012 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, 2012:

 

		As Received Basis (1)
														# of				Proven and Probable Coal Reserves
														SO2/mm				Sulfur Content (1)
Mining Complex		% Ash				% Sulfur				Btu/lb.				Btu				Total				<2%					2-4%			>4%
																		(tons in thousands)
Surface Mining Operations:
Northern Appalachia (principally Ohio)
Cadiz			12.5				3.5				11,400				6.1				8,437				326				5,077				3,034
Tuscarawas County			10.6				4.0				11,767				6.8				8,636				1,164				2,746				4,726
Plainfield			9.3				4.4				11,836				7.5				2,771				--				765				2,006
Belmont County			12.4				4.2				11,823				7.1				12,956				--				3,013				9,943
New Lexington			11.4				4.1				11,729				7.0				3,687				--				1,368				2,319
Harrison (2)			12.8				1.9				11,331				3.4				3,471				2,304				1,167				--
Noble County			11.1				4.9				11,296				8.7				2,741				--				--				2,741
Illinois Basin (Kentucky)
Muhlenberg County			11.2				3.5				11,327				6.2				19,399				--				18,987				412
Underground Coal Reserves:
Tusky			5.3				2.1				12,900				3.2				24,343				3,768				20,575				--

 

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(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 Energy Inc. 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, 2012 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 administrative support staff.  We lease our executive office space at 41 South High Street, Columbus, Ohio, which lease expires February 28, 2015.  In addition, we own buildings primarily for our administrative support and operational support staffs located at 544 Chestnut Street, Coshocton, Ohio and 38175 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 Wall Street Reform and Consumer Protection Act and Item 104 of Regulation S-K for the year ended December 31, 2012 is included in Exhibit 95 to this report.

 

 

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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 March 25, 2013, the closing market price for our common units was $2.50 per unit.  The following table sets forth the range of the daily high and low sales prices and cash distribution per common unit for the periods indicated:

Period		High Price				Low Price				Common Unit Distribution (1)				Subordinated Unit Distribution ( 1)
First Quarter 2011		$	28.34			$	23.36			$	0.4375			$	0.4375
Second Quarter 2011		$	27.75			$	21.59			$	0.4375			$	0.4375
Third Quarter 2011		$	24.37			$	15.04			$	0.4375			$	0.4375
Fourth Quarter 2011		$	18.33			$	14.67			$	0.4375			$	0.4375
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			$	-			$	-

 

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(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 March 25, 2013, we had outstanding 10,475,237 common units, 10,280,380 subordinated units and 423,494 general partner units.  There were approximately 37 record holders of common units on December 31, 2012.  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 receive quarterly distributions on the subordinated units only after sufficient distributions (including any arrearage amounts) have been paid to the common units.

Cash Distribution Policy

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

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

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

 

 

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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 2012.

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

Our ability to pay quarterly cash distributions is also potentially restricted by the operating agreement of Harrison Resources, our joint venture with CONSOL Energy.  Pursuant to the operating agreement, all members of Harrison Resources must approve cash distributions, other than tax distributions, to its members.   In 2012, the members of Harrison Resources did not approve a cash distribution as it was necessary to reserve cash to pay coal reserves acquisition costs.  It is expected that it will be necessary to continue to reserve cash for such purpose rather than paying a cash distribution during all of 2013 and some or all of 2014, and for that reason and otherwise there can be no assurance that we will receive regular cash distributions from Harrison Resources in the future.

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, 2012, the accumulated arrearage amount totaled $2.5 million.

Unregistered Sales of Equity Securities

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

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

 

 

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

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

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

Issuer Purchases of Equity Securities.

We did not make any purchases of our common units, and no such purchases were made on our behalf, during 2012.

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 accounting 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,
		2012				2011				2010					2009				2008
		(in thousands, except per ton amounts)
STATEMENT OF OPERATIONS DATA:
REVENUES:
Coal sales		$	364,928			$	391,046			$	350,057				$	286,661			$	225,538
Other revenue			8,599				9,331				8,369					7,183				4,951
Total revenues			373,527				400,377				358,426					293,844				230,489
COSTS AND EXPENSES:
Cost of coal sales:
Produced coal			288,782				316,574				264,350					200,766				182,922
Purchased coal			23,685				13,480				22,024					19,487				12,925
Total cost of coal sales (excluding depreciation, depletion and amortization)			312,467				330,054				286,374					220,253				195,847
Cost of other revenue			1,195				1,799				2,380					1,245				1,745
Depreciation, depletion and amortization			51,170				51,905				42,329					25,902				16,660
Selling, general and administrative expenses			15,629				13,739				17,257					13,242				9,577
Impairment and restructuring expenses			15,650				-				-					-				-
(Gain) loss on disposal of assets			(8,021	)			1,352				1,228					1,177				(1,407	)
Total costs and expenses			388,090				398,849				349,568					261,819				222,422
(LOSS) INCOME FROM OPERATIONS			(14,563	)			1,528				8,858					32,025				8,067
Interest income			10				13				12					35				62
Interest expense			(11,500	)			(9,870	)			(9,511	)				(6,484	)			(7,720	)
Gain on purchase of business (1)			-				-				-					3,823				-
NET (LOSS) INCOME			(26,053	)			(8,329	)			(641	)				29,399				409
Net income attributable to noncontrolling interest			(755	)			(4,748	)			(6,710	)				(5,895	)			(2,891	)
Net (loss) income attributable to Oxford
Resource Partners, LP unitholders			(26,808	)			(13,077	)			(7,351	)				23,504				(2,482	)
Net (loss) income allocated to general partner			(535	)			(261	)			(147	)				467				(50	)
Net (loss) income allocated to limited partners		$	(26,273	)		$	(12,816	)		$	(7,204	)			$	23,037			$	(2,432	)
Net (loss) income per limited partner unit:
Basic		$	(1.27	)		$	(0.62	)		$	(0.45	)			$	2.09			$	(0.24	)
Diluted		$	(1.27	)		$	(0.62	)		$	(0.45	)			$	2.08			$	(0.24	)
Weighted average number of limited partner units outstanding:
Basic			20,711,952				20,641,127				15,887,977					11,033,840				10,104,324
Diluted			20,711,952				20,641,127				15,887,977					11,083,170				10,104,324
Distributions paid per unit:
Limited partners:
Common		$	1.5125			$	1.7500			$	0.5826		(2)			N/A				N/A
Subordinated		$	0.6375			$	1.7500			$	0.5826		(2)		$	1.2000			$	1.2600
General partner		$	1.0750			$	1.7500			$	0.5826		(2)		$	1.2000			$	1.2600

 

 

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SELECTED FINANCIAL AND OPERATING DATA - (continued)

 

		Oxford Resource Partners, LP Year Ended December 31,
		2012				2011				2010				2009				2008
		(in thousands, except per ton amounts)
STATEMENT OF CASH FLOWS DATA:
Cash flows from:
Operating activities		$	31,776			$	43,467			$	37,868			$	36,870			$	30,823
Investing activities			(8,059	)			(40,377	)			(82,494	)			(47,404	)			(20,773	)
Financing activities			(22,772	)			(947	)			42,149				(2,558	)			8,988
OTHER FINANCIAL DATA:
Adjusted EBITDA (3)		$	47,917			$	58,785			$	58,327			$	62,862			$	27,577
Estimated reserve replacement expenditures			3,868				5,797				3,172				2,371				1,050
Maintenance capital expenditures			17,864				22,635				22,557				25,657				25,321
Mine development expenditures			3,403				4,275				988				686				1,476
Cash reclamation expenditures			8,966				5,751				3,430				3,358				2,594
BALANCE SHEET DATA (at period end):
Cash and cash equivalents		$	3,977			$	3,032			$	889			$	3,366			$	15,179
Accounts receivable			19,792				28,388				28,108				24,403				21,528
Inventory			12,554				12,000				12,640				8,801				5,134
Property, plant and equipment, net			158,483				195,607				198,694				149,461				112,446
Total assets			220,899				261,265				261,071				203,363				171,297
Total debt (current and long-term)			144,527				143,755				102,986				95,711				83,977
OPERATING DATA:
Produced tons			6,817				8,078				7,417				5,781				5,094
Purchased tons			533				380				734				530				434
Tons of coal sold			7,350				8,458				8,151				6,311				5,528
Tons sold under long-term contracts (4)			95.9	%			96.6	%			95.9	%			97.8	%			93.8	%
Coal sales revenue per ton		$	49.65			$	46.23			$	42.95			$	45.42			$	40.94
Below-market sales contract amortization per ton			0.08				0.11				0.17				-				0.14
Cash coal sales revenue per ton			49.57				46.12				42.78				45.42				40.80
Cash cost of coal sales per ton			42.51				39.02				35.13				37.87				35.57
Cash margin per ton		$	7.06			$	7.10			$	7.65			$	7.55			$	5.23

 

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(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.

 

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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.

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:

 

		Year Ended December 31,
		2012				2011				2010				2009				2008
		(in thousands)
Net (loss) income		$	(26,053	)		$	(8,329	)		$	(641	)		$	29,399			$	409
Adjustments:
Interest expense, net of interest income			11,490				9,857				9,499				6,449				7,658
Depreciation, depletion and amortization			51,170				51,905				42,329				25,902				16,660
Impairment and restructuring expenses			15,650				-				-				-				-
(Gain) loss on disposal of assets			(8,021	)			1,352				1,228				1,177				(1,407	)
Below-market coal sales contract amortization			(623	)			(939	)			(1,424	)			(1,705	)			(771	)
Non-cash equity-based compensation expense			1,262				1,077				942				472				468
Non-cash changes in mine reclamation obligations			1,567				3,355				5,742				4,991				4,560
Non-recurring costs			1,475				507				652				(3,823	)			-
Adjusted EBITDA		$	47,917			$	58,785			$	58,327			$	62,862			$	27,577

 

 

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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 “Special Note Regarding Forward-Looking Statements” and under “Risk Factors.” You should read the following discussion in conjunction with “Selected Financial 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 steam coal to U.S. utilities and industrial users, and we are the largest producer of surface mined coal in Ohio.  We focus on acquiring steam coal reserves that we can efficiently mine with our large-scale equipment.  Our reserves and operations are strategically located to serve our primary market area of Illinois, Indiana, Kentucky, 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 19 active surface mines and manage these mines as 8 mining complexes.  Our operations also include two river terminals, strategically located in eastern Ohio and western Kentucky.   For the year ended December 31, 2012, we generated revenues of approximately $373.5 million and a net loss of approximately $26.1 million.   For the year ended December 31, 2012, we produced 6.8 million tons of coal, purchased 0.5 million tons of coal, and sold 7.3 million tons of coal.  Approximately 95.9% of coal tons sold were sold pursuant to long-term coal supply contracts.

Recent Developments

Illinois Basin Restructuring

In the first quarter of 2012, we received a termination notice from a customer related to an 0.8 million tons per year coal supply contract to be fulfilled from our Illinois Basin operations.   In response, we idled one Illinois Basin mine and the related wash plant, closed our Illinois Basin 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.  We have also taken legal action against the customer for wrongful termination of the coal supply agreement.

In the second quarter of 2012, we further adjusted our Illinois Basin operations, varying the mines that were idled to best manage strip ratio impacts and other costs.  We also resumed operations at the wash plant on a limited basis.

In the third quarter of 2012, we idled one additional mine and resumed production at a second mine for a limited period of time that allowed us to meet our coal supply commitments.  The wash plant continued to operate on a limited production basis through most of the quarter and then was again idled .

By the fourth quarter of 2012, production was reduced to two mines.  We have redeployed certain Illinois Basin equipment to our Northern Appalachia operations and are seeking to sell certain excess mining equipment related to these idled operations.

Sale of Oil and Gas Mineral Rights

In April 2012, we completed the sale of certain oil and gas rights on 1,250 acres of land in eastern Ohio for $6.3 million and future royalties.  We expect royalty revenues to be generated from these rights in future periods.

Acquisition of Coal Property

In October 2012, we exchanged mined out land with a fair market value of $1.6 million for a limited warranty deed to specific veins or seams of coal under a 155 acre tract of land in Belmont County Ohio, which we estimate to include approximately 0.7 million coal tons.  As a result of this transaction, we recognized a $1.5 million gain on the sale of assets.

Credit Facility

In June 2012, we amended the Credit Agreement with Citicorp USA, Inc., as Administrative Agent, Citibank, N.A., as Swing Line Bank, Barclays Bank PLC and The Huntington National Bank, as Co-Syndication Agents, Fifth Third Bank and Comerica Bank, as Co-Documentation Agents, and the lenders party thereto to maintain the leverage ratio required as of June 30, 2012 through maturity of the facility.

 

 

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The revolving credit line portion of our existing credit facility matures in July 2013.  Despite our diligent efforts, we have not yet been able to amend the provisions and extend the terms of our credit facility necessitated by maturity.  T he uncertainty regarding the future of our existing credit facility has created substantial doubt about our ability to continue as a going concern.  As a consequence, our auditors have included an emphasis paragraph with respect to this issue in their report on our consolidated financial statements as of and for the year ended December 31, 2012.  Our consolidated 2012 financial statements have been prepared assuming that we will continue as a going concern.  All amounts outstanding under the revolving credit line portion of our existing credit facility have been classified as current liabilities in our consolidated balance sheet as of December 31, 2012.

Our management has been actively working and will continue to work with the lenders to amend the provisions and extend the term of our existing credit facility.  However, there can be no assurance that we will be successful in amending and extending the facility.  Therefore, there can be no guarantee that our existing sources of cash and our future cash flows from operations will be adequate to meet our liquidity requirements, including cash requirements that are due under our existing credit facility or that are needed to fund our business operations.  If we are unable to address our liquidity challenges, then our business and operating results could be materially adversely affected, potentially resulting in the need to curtail our business operations and/or reorganize our capital structure.

The credit agreement related to our existing credit facility, which became effective in July 2010, provides for a credit facility consisting of a $115 million revolving credit line that matures in July 2013, and a $60 million term loan that matures in July 2014.  As of December 31, 2012, we had borrowings of $137.0 million outstanding consisting of $92.0 million on our revolving credit line and $45.0 million on our term loan.  We also had $8.9 million of letters of credit outstanding in support of surety bonds, which bonds are primarily issued to assure performance of our reclamation obligations.

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 or (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 a majority of our coal through supply contracts and anticipate that we will continue to do so.  As of December 31, 2012, we had commitments under supply contracts to deliver 6.5 million, 5.2 million, 4.4 million and 2.5 million tons of coal to customers in 2013, 2014, 2015 and 2016, respectively .  The contracts with delivery commitments amounting to 2.1 million, 4.2 million, and 2.5 million tons of coal in 2014, 2015 and 2016, respectively, have sales price adjustment provisions, subject to certain limitations and adjustments, based on a variety of factors and indices.

Evaluating Our Results of Operations

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

•

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.

 

 

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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, changes in inventory levels, 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 a fixed price, 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 cost-of-living generally.

We evaluate the price we receive for our coal on a coal sales revenue 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
														2012				2011
		Year Ended December 31,												vs.				vs.
		2012				2011				2010				2011				2010
		(in thousands)
Produced tons			6,817				8,078				7,417				(15.6	%)			8.9	%
Purchased tons			533				380				734				40.3	%			(48.2	%)
Tons of coal sold			7,350				8,458				8,151				(13.1	%)			3.8	%
Tons sold under long-term contracts (1)			95.9	%			96.6	%			95.9	%			n/a				n/a
Coal sales revenue per ton		$	49.65			$	46.23			$	42.95				7.4	%			7.6	%
Below-market sales contract amortization per ton			0.08				0.11				0.17				(27.3	%)			(35.3	%)
Cash coal sales revenue per ton			49.57				46.12				42.78				7.5	%			7.8	%
Cash cost of coal sales per ton			42.51				39.02				35.13				8.9	%			11.1	%
Cash margin per ton		$	7.06			$	7.10			$	7.65				(0.6	%)			(7.2	%)
Number of operating days			268.9				270.3				267.7				(0.5	%)			1.0	%

 

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(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.  Our cost of coal sales does not take into account the effects of the cost pass through or cost adjustment provisions in our long-term coal sales contracts, as those provisions result in an adjustment to our coal sales price.

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.

In connection with our Illinois Basin operations, we had a long-term coal purchase contract with a third-party supplier that had favorable pricing terms relative to our production costs.  Under this contract, the third-party supplier was obligated to deliver and we were obligated to purchase 0.4 million tons of coal per year.  In 2011, the supplier asserted that the contract had terminated by its terms, which we disputed.  On March 12, 2013, we entered into a settlement agreement with the supplier under which we agreed to a termination of the contract with the supplier making a one-time payment of $2.1 million to us.

 

 

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In March 2012, we entered into another long-term coal purchase contract with a separate supplier for our Illinois Basin operations for delivery of 350,000 tons of coal in 2012 and 360,000 tons of coal in 2013.  A majority of the tons purchased for the year ended December 31, 2012 were under this new contract as compared to the previously described lower-priced contract for the year ended December 31, 2011.

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
														2012				2011
		Year Ended December 31,												vs.				vs.
		2012				2011				2010				2011				2010
		(tons in thousands)
Cost of coal sales per ton		$	42.51			$	39.02			$	35.13				8.9	%			11.1	%
Produced tons			6,817				8,078				7,417				(15.6	%)			8.9	%
Purchased tons			533				380				734				40.3	%			(48.2	%)
Tons of coal sold			7,350				8,458				8,151				(13.1	%)			3.8	%

 

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.

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.

 

 

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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, 2012, 2011 and 2010:

 

SELECTED FINANCIAL AND OPERATING DATA

		Year Ended December 31,
		2012				2011				2010
		(in thousands)
STATEMENT OF OPERATIONS DATA:
REVENUE:
Coal sales		$	364,928			$	391,046			$	350,057
Other revenues			8,599				9,331				8,369
Total revenues			373,527				400,377				358,426
COSTS AND EXPENSES:
Cost of coal sales:
Produced coal			288,782				316,574				264,350
Purchased coal			23,685				13,480				22,024
Total cost of coal sales (excluding depreciation, depletion and amortization)			312,467				330,054				286,374
Cost of other revenue			1,195				1,799				2,380
Depreciation, depletion and amortization			51,170				51,905				42,329
Selling, general and administrative expenses			15,629				13,739				17,257
Impairment and restructuring expenses			15,650				-				-
(Gain) loss on disposal of assets			(8,021	)			1,352				1,228
Total costs and expenses			388,090				398,849				349,568
(LOSS) INCOME FROM OPERATIONS:			(14,563	)			1,528				8,858
Interest income			10				13				12
Interest expense			(11,500	)			(9,870	)			(9,511	)
NET LOSS			(26,053	)			(8,329	)			(641	)
Net income attributable to noncontrolling interest			(755	)			(4,748	)			(6,710	)
Net loss attributable to Oxford Resource Partners, LP unitholders		$	(26,808	)		$	(13,077	)		$	(7,351	)

 

 

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The following table presents a reconciliation of Net loss to Adjusted EBITDA for years ended December 31, 2012, 2011 and 2010 :

 

Reconciliation of Net loss to Adjusted EBITDA:

 

		Year Ended December 31,
		2012				2011				2010
		(in thousands)
Net loss		$	(26,053	)		$	(8,329	)		$	(641	)
Adjustments:
Interest expense, net of interest income			11,490				9,857				9,499
Depreciation, depletion and amortization			51,170				51,905				42,329
Impairment and restructuring expenses			15,650				-				-
(Gain) loss on disposal of assets			(8,021	)			1,352				1,228
Below-market coal sales contract amortization			(623	)			(939	)			(1,424	)
Non-cash equity-based compensation expense			1,262				1,077				942
Non-cash changes in mine reclamation obligations			1,567				3,355				5,742
Non-recurring costs			1,475				507				652
Adjusted EBITDA (1)			47,917				58,785			$	58,327

 

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(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, 2012 Compared to Year Ended December 31, 2011

Overview

Net loss allocated to limited partners for the year ended December 31, 2012 was $26.3 million, or $1.27 per diluted limited partner unit, compared to $12.8 million, or $0.62 per diluted limited partner unit, for the year ended December 31, 2011.  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.  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 with a value 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

Royalty income and other revenue, primarily limestone sales, was $8.6 million for the years 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 for the year ended December 31, 2012, an increase of $2.4 million, compared to $3.5 million 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.

 

 

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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 a rise in cost of $12.0 million for purchased coal, $10.8 million for diesel fuel and $4.7 million for lease expense, partially offset by decreases in supplies and wages and employee benefits costs of $0.9 million and $0.8 million, respectively.  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 $2.1 million due to higher spot prices in 2012 resulting in $10.8 million in additional diesel fuel expense, offset by $8.7 million in diesel fuel cost savings from producing 1.3 million fewer coal tons for the year ended December 31, 2012, compared to the year ended December 31, 2011.  Lease expense increased $4.7 million due to the business decisions to replace owned mining equipment that was retired with leased mining equipment.

Transportation expense was $43.6 million for the year ended December 31, 2012, a decrease of $3.7 million from $47.3 million for the year ended December 31, 2011.  The reduction in tons shipped, which accounted for $6.2 million of the decrease, was partially offset by a $0.33 per ton, or $2.5 million, increase in transportation costs.

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 were 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 $15.7 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 our continuing 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 Energy.  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.

 

 

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Year Ended December 31, 2011 Compared to Year Ended December 31, 2010

Overview

Net loss allocated to limited partners for the year ended December 31, 2011 was $12.8 million, or $0.62 per diluted limited partner unit, compared to $7.2 million, or $0.45 per diluted limited partner unit, for the year ended December 31, 2010.  Total revenue was $400.4 million for the year ended December 31, 2011, an increase of $42.0 million, or 11.7%, from $358.4 million for the year ended December 31, 2010.  Adjusted EBITDA was $58.8 million for the year ended December 31, 2011, an increase of $0.5 million from $58.3 million for the year ended December 31, 2010.  Cash margin per ton was $7.10 for the year ended December 31, 2011, a decrease of $0.55 per ton, or 7.2%, from $7.65 per ton for the year ended December 31, 2010.

Coal Sales Revenue

Coal sales revenue was $391.1 million for the year ended December 31, 2011, an increase of $41.0 million, or 11.7%, from $350.1 million for the year ended December 31, 2010.  The increase was primarily attributable to a 7.6% increase in coal sales revenue per ton, which increased $3.28 per ton to $46.23 per ton for the year ended December 31, 2011 from $42.95 per ton for the year ended December 31, 2010.  The increase of $3.28 per ton resulted in a $27.8 million increase in coal sales revenue for the year ended December 31, 2011.  Also contributing to the increase in coal sales revenue was a 0.3 million increase in coal tons sold resulting in an additional $13.2 million in incremental coal sales revenue for the year ended December 31, 2011.

Other Revenue

Royalty income and other revenue, primarily limestone sales, was $9.3 million for the year ended December 31, 2011, an increase of $0.9 million, or 11.5%, from $8.4 million for the year ended December 31, 2010.  Limestone sales were $3.5 million for the year ended December 31, 2011, an increase of $2.0 million, compared to $1.5 million for the year ended December 31, 2010.  This increase was enhanced by a $0.4 million increase in royalty income, offset by a $1.5 million decrease in non-coal revenue attributable to receipt of a non-recurring contract termination payment of $1.8 million in the year ended December 31, 2010.

Cost of Coal Sales (Excluding DD&A)

Cost of coal sales (excluding DD&A) was $330.1 million for the year ended December 31, 2011, an increase of $43.7 million, or 15.3%, from $286.4 million for the year ended December 31, 2010.  The increase was attributable to an increase of 0.3 million in tons sold, which corresponds to a $10.8 million increase in cost of coal sales.  Cost of coal sales per ton was $39.02 for the year ended December 31, 2011, an increase of $3.89, or 11.1%, per ton from $35.13 per ton for the year ended December 31, 2010.  The $3.89 per ton increase corresponds to a $32.9 million increase in cost of coal sales, primarily attributable to a rise in price of $14.0 million, $6.3 million and $3.8 million for diesel fuel, labor, and repairs and maintenance, respectively, and was partially offset by decreases in rent and contract labor each of $2.1 million, respectively.  Diesel fuel expense increased $15.9 million due to higher spot prices in 2011 resulting in $14.0 million in additional diesel fuel expense, plus $1.9 million in additional diesel fuel cost from producing 0.7 million additional coal tons for the year ended December 31, 2011 compared to the year ended December 31, 2010.  Labor expenses increased $8.6 million, of which $1.9 million is the result of our workforce performing most of the auguring and high wall mining activities for the year ended December 31, 2011, activities which were outsourced during the year ended December 31, 2010.  Additionally we incurred higher wage and benefits costs totaling approximately $6.7 million to maintain a skilled and knowledgeable workforce within the market and to produce 0.7 million additional coal tons for the year ended December 31, 2011 compared to the year ended December 31, 2010.  Repairs and maintenance expense increased $4.9 million for the year ended December 31, 2011 compared to the year ended December 31, 2010 was the result of higher component costs representing approximately $3.8 million of the increase in addition to $1.1 million in cost associated with 0.7 million additional coal tons production.

 

 

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For the year ended December 31, 2011, 379,968 tons of coal were purchased at an average price of $35.48 per ton, which represents decreases of 354,125 tons and $5.47 per ton, respectively, compared to 734,093 tons of coal purchased at an average price of $30.00 per ton, respectively, for the year ended December 31, 2010.

Transportation expenses were $47.3 million for the year ended December 31, 2011, an increase of $8.8 million, or 22.9%, from $38.5 million for the year ended December 31, 2010.  The increase is the result of a $7.4 million increase in transportation costs and $1.4 million increase in tons shipped.  Transportation expenses per ton sold increased 18.4% to $5.59 for the year ended December 31, 2011 from $4.72 for the year ended December 31, 2010.

Depreciation, Depletion and Amortization

DD&A expense was $51.9 million for the year ended December 31, 2011, an increase of $9.6 million, or 22.6%, from $42.3 million for the year ended December 31, 2010.  The $4.2 million increase in depreciation expense to $36.9 million for the year ended December 31, 2011 primarily resulted from the full year impact of depreciation on equipment purchased in 2010 with the proceeds from our initial public offering and borrowings under our credit facility.  The $5.6 million increase in amortization expense primarily resulted from the increase in cost estimates associated with measuring our reclamation and mine closure costs.

Selling, General and Administrative Expenses

Selling, general and administrative expenses were $13.7 million for the year ended December 31, 2011, a decrease of $3.6 million, or 20.4%, from $17.3 million for the year ended December 31, 2010.  This decrease primarily resulted from reductions in public company costs of $0.8 million incurred in connection with our initial public offering and the non-recurring cost of termination of a professional service contract for $2.5 million in 2010.

(Gain) Loss on Disposal of Assets

The loss on disposal of assets of $1.3 million for the year ended December 31, 2011 represented an increase of $0.1 million from a loss of $1.2 million for the year ended December 31, 2010.  The loss, substantially unchanged year-over-year, was the result of 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 Energy.  Net income attributable to noncontrolling interest was $4.7 million for the year ended December 31, 2011, a decrease of $2.0 million from $6.7 million for the year ended December 31, 2010.  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, fund capital expenditures, including acquisitions from time to time, service our debt and pay cash distributions to our unitholders.  Our primary sources of liquidity to meet these needs are cash generated by our operations and borrowings under the Credit Agreement.  Also, if we are able to effect any asset sales associated with our Illinois Basin restructuring at acceptable values, our liquidity will be enhanced by those amounts.

Our ability to satisfy our working capital requirements and debt service obligations, fund planned capital expenditures, and pay quarterly distributions to the unitholders 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.

 

 

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In June 2012, we amended the Credit Agreement to maintain the leverage ratio required as of June 30, 2012 through maturity of the facility.

As of December 31, 2012, our available liquidity was $18.1 million, which consisted of $4.0 million in cash on hand and $14.1 million of borrowing capacity under the Credit Agreement.

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,
		2012				2011				2010
		(in thousands)
Net cash provided by (used in):
Operating activities		$	31,776			$	43,467			$	37,868
Investing activities			(8,059	)			(40,377	)			(82,494	)
Financing activities			(22,772	)			(947	)			42,149

 

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

Net cash from operating activities was $31.8 million for the year ended December 31, 2012 compared to $43.5 million for the year ended December 31, 2011, a decrease of $11.7 million.   The decrease was primarily attributable to a $17.2 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 $5.5 million favorable changes 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 our continuing restructuring of our Illinois Basin operations.   The $5.5 million favorable change in working capital comprised of $8.9 million in accounts receivable, $4.7 million in accounts payable and $3.1 million in deferred revenue, partially offset by the comparatively unfavorable changes of $4.0 million in reclamation and mine closure costs and other liabilities, and $2.3 million in inventory.  The accounts receivable change is primarily due to 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 $8.1 million for the year ended December 31, 2012, compared to $40.4 million for the year ended December 31, 2011, a decrease of $32.3 million.  This decrease is primarily attributable to a $14.7 million decrease in the purchase of property and equipment and $11.6 million in proceeds from the sale of property and equipment.  The $14.7 million decrease in the purchase of property and equipment is 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 on-going 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 $21.8 million was primarily attributable to a $4.7 million reduction in debt and a $14.1 million reduction in distributions to partners, partially offset by a $35.0 million decrease in advances on our revolving credit line compared to the year ended December 31, 2011.

 

 

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Year Ended December 31, 2011 Compared to Year Ended December 31, 2010

Net cash from operating activities was $43.5 million for the year ended December 31, 2011 compared to $37.9 million for the year ended December 31, 2010, an increase of $5.6 million.  This increase is primarily attributable to comparatively favorable changes in working capital components, including $5.3 million in inventory and $3.4 million in accounts receivable, partially offset by the comparatively unfavorable changes of $2.6 million in reclamation and mine closure costs and $2.1 million in cash contributed by operations (calculated as net loss adjusted for non-cash items).  The accounts receivable change, primarily due to timing of payments in December 2009, and inventory change, primarily due to higher coal inventory levels at year-end 2010 compared to year-ends 2011 and 2009, are typical within the industry and not indicators of a change in future or past trends.

Net cash used in investing activities was $40.4 million for 2011, a decrease of $42.1 million from net cash used in investing activities of $82.5 million for 2010.  This decrease was primarily attributable to the purchases of major mining equipment and the buy-out of equipment under operating leases that occurred in the third quarter of 2010 with proceeds of our initial public offering and borrowings under our credit facility.

Net cash used in financing activities was $0.9 million for the year ended December 31, 2011 compared to $42.1 million provided by financing activities for the year ended December 31, 2010, a decrease of $43.0 million.  The decrease in net cash from financing activities was primarily attributable to transactions related to our initial public offering that occurred in 2010.  In 2010, we received proceeds of $144.4 million from our initial public offering, net of $6.1 million of offering expenses, and concurrently refinanced our credit facility receiving proceeds of $54.4 million, net of $5.6 million of debt issuance costs.  In addition, from 2010 to 2011, we had a net increase in the change in revolving credit line borrowings of $18.5 million, a net decrease in the change in payments on borrowings of $86.3 million, and a decrease in distributions to partners of $50.3 million.  In addition, we paid off $96.5 million of existing debt, which is the primary factor responsible for the change in payments on borrowings.  While our quarterly distributions to our partners in 2011 were substantially more than our quarterly distributions to them in 2010, we also made significant distributions to our partners in 2010 related to our initial public offering.  As a result, our aggregate distributions to partners were more in 2010 than in 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 Credit Agreement, and proceeds from asset sales.

The following table summarizes our capital expenditures by type for the years ended December 31, 2012 and 2011:

 

		Year Ended December 31,
		2012				2011
		(in thousands)
Coal reserves		$	1,761			$	1,075
Mine development			3,402				5,243
Equipment and components			19,313				25,651
Total		$	24,476			$	31,969

 

Credit Facility

The credit agreement related to our $175 million credit facility (the "Credit Agreement"), which became effective July 19, 2010, provides for a credit facility consisting of a $60 million term loan and a $115 million revolving line of credit.  As of December 31, 2012, we had borrowings of $137.0 million outstanding consisting of $45.0 million on our term loan and $92.0 million on our revolving line of credit.  We also had $8.9 million of letters of credit outstanding in support of surety bonds, which bonds are primarily issued for reclamation obligations.

Under the Credit Agreement we are required to make quarterly principal payments of $1.5 million on the $60 million term loan commencing on September 30, 2010 and continuing until the maturity in July 2014, when the remaining balance is to be paid.  The $115 million revolving credit line matures in July 2013.  Borrowings under the Credit Agreement bear interest at a variable rate per annum equal to, at our option, the London Interbank Offered Rate or the Base Rate plus the Applicable Margin (as defined in the Credit Agreement).  The Credit Agreement contains customary covenants, including restrictions on our ability to incur additional indebtedness, make certain investments, make distributions to our unitholders, make ordinary course dispositions of assets over predetermined levels, and enter into equipment leases, as well as enter into a merger or sale of all or substantially all of our property or assets, including the sale or transfer of interests in our subsidiaries.  The Credit Agreement also requires compliance with certain financial covenants, including leverage and interest coverage ratios, as well as capping capital expenditures in any fiscal year to certain predetermined amounts.  Borrowings under the Credit Agreement are secured by a first-priority lien on and security interest in substantially all of our assets.

 

 

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In June 2012, an amendment to the Credit Agreement was executed that modified certain provisions.  The amendment, applicable for the remaining term of the Credit Agreement, (i) modified the leverage ratio, (ii) authorized the sale of certain Kentucky assets, and (iii) allows quarterly distributions at minimum levels and additionally at certain higher levels as long as specified liquidity thresholds are maintained after giving effect to the distribution.

As discussed in “Part I, Item 1, Business —Going Concern Considerations ,” the uncertainty regarding the future of our existing credit facility has created substantial doubt about our ability to continue as a going concern.  As a consequence, our independent registered public accounting firm (our “auditors”) has included an emphasis paragraph with respect to this issue in their report on our consolidated financial statements as of and for the year ended December 31, 2012 included in the Annual Report on Form 10-K.  Our consolidated 2012 financial statements have been prepared assuming that we will continue as a going concern.  All amounts outstanding under the revolving credit line portion of our existing credit facility have been classified as current liabilities in our consolidated balance sheet as of December 31, 2012.

Our management has been actively working and will continue to work with the lenders to amend the provisions and extend the term of our existing credit facility.  However, there can be no assurance that we will be successful in amending and extending the facility.  Therefore, there can be no guarantee that our existing sources of cash and our future cash flows from operations will be adequate to meet our liquidity requirements, including cash requirements that are due under our existing credit facility or that are needed to fund our business operations.  If we are unable to address our liquidity challenges, then our business and operating results could be materially adversely affected, potentially resulting in the need to curtail our business operations and/or reorganize our capital structure.  Accordingly, there is substantial doubt that we will be able to continue as a going concern.

Contractual Obligations

We have contractual obligations that are required to be settled in cash.  The amounts of our contractual obligations as of December 31, 2012 were as follows:

 

		Payment Due by Period
		Total				Less than one year				1 - 3 Years				4 - 5 Years				More than five Years
						(in thousands)
Long-term debt obligations		$	137,000			$	98,000			$	39,000			$	-			$	-
Future interest obligations - long-term debt (1)			6,332				5,194				1,138				-				-
Other long-term debt (2)			7,521				4,964				2,557				-				-
Future interest obligations - other long-term debt			568				424				144				-				-
Fixed-price diesel fuel purchase contracts			37,391				37,391				-				-				-
Operating lease obligations			23,069				7,595				15,124				350				-
Total		$	211,881			$	153,568			$	57,963			$	350			$	-

 

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(1)

Interest on variable rate long-term debt was calculated using rates estimated by us at December 31, 2012 for the remaining term of outstanding borrowings.

(2)

Represents various notes payable with interest rates ranging from 4.6% to 6.75%.

 

 

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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.  Typically, we secure these obligations with surety bonds supported by letters of credit.  If surety bonds became unavailable, we would seek to secure our reclamation obligations with letters of credit, cash deposits or other suitable forms of collateral.

As of December 31, 2012, we had $37.7 million of surety bonds outstanding and de minimis cash bonds to secure certain reclamation obligations.  Additionally, as of December 31, 2012, we had $8.9 million of letters of credit outstanding in support of these bonds.  Further, as of December 31, 2012, we had $0.6 million of road bonds and $2.7 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 position, liquidity or operations therefrom.

Critical Accounting Policies and Estimates

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

Operating Environment and Risk Factors

We, in the course of our business activities, are exposed to a number of risks, including: fluctuating market conditions of coal, truck and rail transportation, fuel costs, changing government regulations, unexpected maintenance and equipment failure, employee benefits cost control, changes in estimates of proven and probable coal reserves, as well as our ability to maintain adequate financing, necessary mining permits and control of sufficient recoverable coal properties.  In addition, adverse weather and geological conditions may increase mining costs, sometimes substantially.

Investment in Joint Venture

Investments in other entities are accounted for using the consolidation, equity method or cost basis depending upon the level of ownership, our ability to exercise significant influence over the operating and financial policies of the investee, and whether we are determined to be the primary beneficiary of a variable interest in an entity.

In January 2007, Oxford Mining entered into a joint venture, Harrison Resources, with a subsidiary of CONSOL Energy to mine surface coal reserves purchased from CONSOL Energy.   To initially capitalize the joint venture, we contributed coal reserves and mine development for a 51% ownership interest in the joint venture.  We consolidate all of Harrison Resources' accounts with all material intercompany transactions and balances being eliminated in our consolidated financial statements.  The 49% portion of Harrison Resources that we do not own is reflected as "noncontrolling interest" in our consolidated balance sheets and statements of operations.

Concentrations of Credit Risk

We do not require collateral or other security on accounts receivable.  Credit risk is controlled through credit approvals and monitoring procedures.  Please read Note 19: Commitments and Contingencies to the audited consolidated financial statements included elsewhere in this report for a discussion of major customers.

 

 

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Asset Impairments

We follow the accounting guidance on the impairment or disposal of property, plant and equipment, which requires that projected future cash flows from use and disposition of assets be compared with the carrying amounts of those assets when potential impairment is indicated.  When the sum of projected undiscounted cash flows is less than the carrying amount, impairment losses are recognized.  In determining such impairment losses, we must determine the fair value for the assets in question in accordance with the applicable fair value accounting guidance.  Once the fair value is determined, the appropriate impairment loss must be recorded as the difference between the carrying amount of the assets and their respective fair values.  Also, in certain situations, expected mine lives are shortened because of changes to planned operations.  When that occurs and it is determined that the mine's underlying costs are not recoverable in the future, reclamation and mine closing obligations are accelerated and the reclamation and mine closing costs accrual is increased accordingly.  To the extent it is determined that asset carrying values will not be recoverable during a shorter mine life, a provision for such impairment is recognized.  We recorded an impairment loss of $12.8 million in 2012 related to certain mining assets in the Illinois Basin that are to be disposed of by sale.  Please read Note 4: Impairment and Restructuring Expenses to the audited consolidated financial statements included elsewhere in this report for a discussion of this asset impairment loss recorded in 2012.  There were no impairment losses recorded during the years ended December 31, 2011 and 2010.

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.  We estimate our future cost requirements for reclamation of land where we have conducted surface and underground mining operations, based on our interpretation of the technical standards of regulations enacted by the U.S. Office of Surface Mining, as well as state regulations.  These costs relate to reclaiming the pit and support acreage at surface mines and sealing portals at underground mines.  Other reclamation costs are related to refuse and slurry ponds, as well as holding and related termination or exit costs

 

Effective June 30, 2011, we changed our method for estimating reclamation and mine closure costs from the current disturbance method to the end of mine life method.   This represents a change in accounting estimate effected by a change in method.  The end of mine life method, which is a preferable method under GAAP, 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.

 

The change in accounting method resulted in a reclassification of certain costs on our consolidated balance sheet as of June 30, 2011.  Approximately $6.2 million was reclassified from the current portion to the long-term portion of reclamation and mine closure costs.  The impact of the change in method was negligible to our consolidated statement of operations.  This change was accounted for in the quarter ended June 30, 2011 and all financial statement measurement periods subsequent thereto, in accordance with ASC 250.

 

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 coal reserves.  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 costs 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 costs 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 and mine closure costs liability and make adjustments for permit changes, cost revisions, changes to mining plans and the timing of expenditures.

 

 

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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.  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 coal royalties, commissions and service fees.  We receive an overriding royalty on underground coal reserves that we sublease to a third party mining company.  For the years ended 2012, 2011 and 2010, we received royalties of $1.5 million, $3.2 million and $2.8 million, respectively.  In 2012, we also received an advance royalty payment of $2.2 million in exchange for a significant reduction in the amount of the overriding royalty going forward.

We also receive commissions from a third party who sells limestone that we recover during our coal mining process.  Additionally, we receive service fees for operating a coal unloading facility, providing river barge loading services to a third-party coal mining company, and ash hauling.  In August 2011, we terminated a services agreement under which we provided landfill earth moving and transportation services.  Revenues are recognized when earned or when services are performed.

Derivative Financial Instruments

We use diesel fuel forward contracts to manage the risk of fluctuations in the cost of diesel fuel.  Our diesel fuel forward contracts qualify for the normal purchase-normal sale exception prescribed by the accounting guidance on derivatives and hedging, based on the terms of the contracts and management's intent and ability to take physical delivery of the diesel fuel.

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.

New Accounting Standards Issued

There were various other 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.

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 risk for coal sales through the use of supply contracts and the use of forward contracts.

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 purchases to manage the exposure related to this volatility.   Additionally we are protected 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 $1.0 million for the year ended December 31, 2012.

 

 

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A hypothetical increase of 10% in explosives prices would have increased the net loss by $2.7 million for the year ended December 31, 2012.

Interest Rate Risk

We will from time to time adjust our exposure to interest rate risk 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 w e have exposure to changes in interest rates on our indebtedness associated with our credit agreement.  At December 31, 2012, the variable interest rate on our debt under the Credit Agreement was 5.51%.  Based on our borrowings at the end of 2012, 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 $1.5 million.

ITEM   8.                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-30 of this report 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 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, 2012, 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.

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.

 

 

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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 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 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 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.

The effectiveness of our internal control over financial reporting as of December 31, 2012 has been audited by Grant Thornton LLP, an independent registered public accounting firm, as stated in their report dated April 1, 2013 with respect to the consolidated financial statements and internal controls over financial reporting included in the Annual Report on Form 10-K for the year ended December 31, 2012 of Oxford Resource Partners, LP.

 

 

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REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

Board of Directors and Unitholders

Oxford Resource Partners, LP

We have audited Oxford Resource Partners, LP’s (a Delaware limited partnership) internal control over financial reporting as of December 31, 2012, based on criteria established in Internal Control—Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO).  Oxford Resource Partners, LP’s management is responsible for maintaining effective internal control over financial reporting and for its assessment of the effectiveness of internal control over financial reporting, included in the accompanying Management’s Annual Report on Internal Control Over Financial Reporting.  Our responsibility is to express an opinion on Oxford Resource Partners, LP’s internal control over financial reporting based on our audit.

We conducted our audit in accordance with the standards of the Public Company Accounting Oversight Board (United States).  Those standards require that we plan and perform the audit to obtain reasonable assurance about whether effective internal control over financial reporting was maintained in all material respects.  Our audit included obtaining an understanding of internal control over financial reporting, assessing the risk that a material weakness exists, testing and evaluating the design and operating effectiveness of internal control based on the assessed risk, and performing such other procedures as we considered necessary in the circumstances.  We believe that our audit provides a reasonable basis for our opinion.

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

Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements.  Also, 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.

In our opinion, Oxford Resource Partners, LP maintained, in all material respects, effective internal control over financial reporting as of December 31, 2012, based on criteria established in Internal Control—Integrated Framework issued by COSO.

We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), the consolidated balance sheets of Oxford Resource Partners, LP (a Delaware limited partnership) and subsidiaries (the “Partnership”) as of December 31, 2012 and 2011, and the related consolidated statements of operations, partners’ capital and cash flows for each of the three years in the period ended December 31, 2012, and our report dated April 1, 2013 expressed an unqualified opinion.

 

/s/ GRANT THORNTON LLP

 

Cleveland, Ohio

April 1, 2013

 

 

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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, 2012 that have materially affected, or are reasonably likely to materially affect, our internal control over financial reporting.

 

ITEM 9B.             OTHER INFORMATION

 

Effective March 29, 2013, our general partner entered into new employment agreements (the “New Agreements”) with each of the following named executive officers: (i) Charles C. Ungurean, President and Chief Executive Officer, (ii) Daniel M. Maher, Senior Vice President, Chief Legal Officer and Secretary, (iii) Gregory J. Honish, Senior Vice President, Operations, and (iv) Michael B. Gardner, Vice President - Legal Officer, General Counsel – Regulatory/Environmental and Assistant Secretary (individually an “EA Referenced Officer” and collectively the “EA Referenced Officers”).  The New Agreements establish customary employment terms for the Referenced Officers including base salaries, bonuses and other incentive compensation and other benefits and provision for duties and titles, and replace and supersede the prior employment agreements which had been in effect between our general partner and each of the EA Referenced Officers (individually a “Prior Agreement” and collectively the “Prior Agreements”).

The primary reasons for entering into the New Agreements were twofold.  First, the Prior Agreements had terms expiring December 31, 2013, and, notwithstanding the automatic extension provisions set forth in the Prior Agreements, our general partner’s Board of Directors (the “Board”) and the Compensation Committee of the Board (the “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.  And second, the target bonus amounts for certain of the EA Referenced Officers are being increased with those increased amounts being reflected in the New Agreements.

The change from the Prior Agreements made in all of the New Agreements for the EA Referenced Officers is an extension of the initial terms thereof to run until December 31, 2014.  The other changes from the Prior Agreements made in the New Agreements for Messrs. Charles Ungurean, Maher and Honish are to confirm the increase in the annual target incentive bonus amount to 125% of annual base salary in the case of Mr. Charles Ungurean and to 100% in the cases of Messrs. Maher and Honish, all of which was approved by the Compensation Committee and the Board.

In addition, and also effective March 29, 2013, our general partner entered into retention bonus letter agreements (the “Retention Agreements”) with each of the following named executive officers: (i) Bradley W. Harris, Senior Vice President, Chief Financial Officer and Treasurer, (ii) Daniel M. Maher, Senior Vice President, Chief Legal Officer and Secretary, and (iii) Gregory J. Honish, Senior Vice President, Operations (individually a “RA Referenced Officer” and collectively the “RA Referenced Officers”).  The purpose of the Retention Agreements is to better improve the chances of our general partner retaining the services of the RA Referenced Officers, which retentions our general partner has determined to be important for us.  The bonuses for which each RA Referenced Officer is eligible is in an aggregate amount equal to his base salaries, and vest and become payable one-third upon completion of a satisfactory refinancing of our credit facility and two-thirds upon completion of continued employment of the applicable RA Referenced Officer through December 31, 2014.

The foregoing description of certain terms and conditions of the New Agreements, rights and obligations of our general partner and the EA Referenced Officers in connection therewith and changes from the Prior Agreements are qualified by reference in their entirety to the definitive terms and conditions of the New Agreements and the Prior Agreements, copies of which are included with this Annual Report on Form 10-K and incorporated herein by reference.  Further, the foregoing description of certain terms and conditions of the Retention Agreements, and rights and obligations of our general partner and the RA Referenced Officers in connection therewith, are qualified by reference in their entirety to the definitive terms and conditions of the Retention Agreements, 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 is not elected by our unitholders and will not be subject to re-election in the future.  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	77	Chairman of the Board
Charles C. Ungurean	63	Director, President and Chief Executive Officer
Bradley W. Harris	53	Senior Vice President, Chief Financial Officer and Treasurer
Daniel M. Maher	67	Senior Vice President, Chief Legal Officer and Secretary
Gregory J. Honish	56	Senior Vice President, Operations
Michael B. Gardner	57	Vice President-Legal, General Counsel-Regulatory/Environmental and Assistant Secretary
Denise M. Maksimoski	38	Senior Director of Accounting
Brian D. Barlow	42	Director
Matthew P. Carbone	46	Director
Gerald A. Tywoniuk	51	Director
Peter B. Lilly	64	Director
Robert J. Messey	67	Director

 

George E. McCown was elected Chairman of the board of directors of our general partner in 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 an MBA 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 of Stanford’s board of trustees.

 

 

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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.

 

Charles C. Ungurean was elected President and Chief Executive Officer and a member of the board of directors of our general partner 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.  He has served as the President and Chief Executive Officer of our general partner since its formation in 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 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 newly-acquired Trinity Coal Corporation (an Appalachian 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 producer of coal with reserves in Northern and Central Appalachia and in the Illinois Basin, 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 in his last eight years there as an Audit Senior Manager.  Mr. Harris is a certified public accountant and earned a B.S. in Accounting from Lehigh University in 1981 and an MBA from Lehigh University in 1986.

 

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 33-year professional career at mines in Northern Appalachia, Central Appalachia, the Illinois Basin and the PRB.  He is a Licensed Professional Engineer in Ohio and West Virginia and a Certified Surface Mine Foreman in Ohio and Wyoming.  Mr. Honish holds a B.S. in Mining Engineering from the University of Wisconsin.

 

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, the largest privately-owned coal mining company in the United States.  While at Murray Energy, Mr. Gardner served as an officer of several Murray Energy subsidiaries.  Mr. Gardner is a licensed attorney in Ohio with more than 30 years of experience in the coal industry and in environmental regulatory compliance management.  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, an MBA from Ashland University and a B.S. in Environmental Biology from Ohio University.

 

 

 

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Denise M. Maksimoski has served as Senior Director of Accounting of our general partner since December 2009, prior to which she was 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 in various positions including most recently as an Audit Senior Manager from August 2005 to August 2008.  Ms. Maksimoski is a certified public accountant and earned a B.A. degree in Accounting and Actuarial Studies from Thiel College.

 

Brian D. Barlow was elected as a member of the board of directors of our general partner in 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, he was a Senior Securities Analyst for Scion Capital, a private investment partnership located in Cupertino, California, from August 2004 to August 2006.  Mr. Barlow received an MBA from Columbia Business School and a B.A. from the University of Washington.

 

Mr. Barlow’s 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 as a member of the board of directors of our general partner in 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 an MBA 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 as a member of the board of directors of our general partner in June 2010.  Prior to joining the board of directors of our general partner, 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 through his company, Harm Group, LLC.  Before that, Mr. Lilly was an executive officer with CONSOL Energy Inc., the largest producer of high-Btu bituminous coal in the United States.  Mr. Lilly joined CONSOL Energy 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 Energy, 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 is currently a member of Harm Group, LLC, which serves as a consultant to financial analysts on issues related to the coal industry.  Mr. Lilly received a B.S. in General Engineering and Applied Science from the United States Military Academy at West Point in 1970 and served in the U.S. Army until 1975.  He obtained an MBA from Harvard Business School in 1977.

 

 

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Mr. Lilly’s 30 plus years of experience in the coal industry, much of it in significant 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 as a member of the board of directors of our general partner in 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, one of the largest U.S. coal producers, from December 2000 until April 2008. Prior to Arch Coal, he served from 1993 as chief financial officer of Sverdrup, a large privately held engineering, architecture, construction and technology services firm, until its acquisition in 1999 by Jacobs Engineering Group, Inc., one of the largest global firms providing engineering, architecture, construction and technology 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 from 1968 to 1992, and during that period served as an SEC Audit Partner from 1981 to 1992.  He currently serves as a director and audit committee chairperson on the board of Stereotaxis (NASDAQ:STXS), and additionally serves on the compensation committee of Stereotaxis’ board.  Mr. Messey also serves on the advisory board of Mississippi Lime Company, a non-public trust, and is chairperson of the audit committee and serves on the compensation committee of that advisory board.  Mr. Messey is a certified public accountant, and he attended Washington University in St. Louis, Missouri where he received a B.S. in business administration.

 

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 large privately held company and 11 years as an SEC audit partner.  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 as a member of the board of directors of our general partner in January 2009.  In July 2011, he became a part-time Senior Consultant to the Chief Financial Officer of CIBER, Inc., a global information technology services company. Prior thereto, from May 2010 to July 2011, Mr. Tywoniuk served as interim Senior Vice President, Finance of CIBER, Inc.  Mr. Tywoniuk continues to act on a part-time consulting basis as the Plan Representative for the plan of liquidation of Pacific Energy Resources Ltd., an oil and gas acquisition, exploitation and development company.  Mr. Tywoniuk joined Pacific Energy Resources Ltd. in June 2008 as Senior Vice President, Finance and he was appointed Chief Financial Officer in August 2008.  He was also appointed acting Chief Executive Officer in September 2009.  He held these positions as an employee until May 2010.  Mr. Tywoniuk joined Pacific Energy Resources Ltd. in June 2008 to help the management team work through the company’s financially distressed situation.  Prior to joining Pacific Energy Resources Ltd., Mr. Tywoniuk acted as an independent consultant in accounting and finance from March 2007 to June 2008.  From December 2002 through November 2006, Mr. Tywoniuk was Senior Vice President and Chief Financial Officer of Pacific Energy Partners, LP.  From November 2006 to March 2007, Mr. Tywoniuk assisted with the integration of Pacific Energy Partners, LP after it was acquired by Plains All American Pipeline, L.P.

 

Mr. Tywoniuk holds a Bachelor of Commerce degree from The University of Alberta, Canada, and is a Canadian chartered accountant.  He currently serves as a director and audit committee chairperson on the board of American Midstream Partners, LP.

 

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.”

 

 

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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, or 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 to it 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.

 

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 of the board of directors.  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.

 

 

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The Audit Committee is authorized to recommend periodically to the board of directors any changes or modifications to its charter that the Audit Committee believes may be required or desirable.

 

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   or at the following address and fax number: Name of the Director(s), c/o Secretary, Oxford Resource Partners, LP, 41 South High Street, Suite 3450, Columbus, Ohio 43215, 614-754-7100.

 

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, 2012, except that three Form 4s, reporting the common units issued on September 30, 2012 to Peter B. Lilly, Robert J. Messey and Gerald A. Tywoniuk as quarterly independent director compensation, were untimely filed three days late.

 

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 fiscal year ended December 31, 2012 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;

 

 

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·

Jeffrey M. Gutman, former 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;

 

·

Thomas T. Ungurean, former Senior Vice President, Equipment, Procurement and Maintenance; 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 yearly performance and for their individual performances during the fiscal year; and (iii) equity-based awards granted under the Oxford Resource Partners, LP Amended and Restated Long-Term Incentive Plan (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 named executive officers and their contributions to our company-wide performance;

 

·

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 at the outset of 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 CEO 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.

 

 

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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 2012 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 and March 2012, and also in January 2013, 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.  Historically and in 2012, the Board has used and did use the amount of distributable cash flow available for the cash distributions made to our equityholders as the primary measure of our operating performance.  For a discussion of cash distributions and related matters, please read “Item 5. Market for Registrant’s Common Equity, Related Unitholder Matters and Issuer Purchases of Equity Securities — Cash Distribution Policy.”  In addition, 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 2012.  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 as executive officers individuals with the skills necessary to execute our business strategy and develop, grow and manage our business.

 

For each of the 2012 and 2013 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 in 2012 consisted of Alliance Resource Partners, L.P., Alpha Natural Resources, Cloud Peak Energy, Crosstex Energy, L.P., Hallador Energy Company, James River Coal Company, Natural Resource Partners, L.P., Patriot Coal Corporation, Rhino Resource Partners, L.P., Walter Energy, Inc. and Westmoreland Coal Company.  The peer group of companies to be utilized in 2013 has been updated to 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.  Although the Board and our Compensation Committee review compensation data relating to our peer group of companies, prior to 2012 they did not benchmark compensation at any particular level relative to our peer group.  For 2012 and going forward, the Board and our Compensation Committee have benchmarked generally and intend to continue to benchmark generally compensation in a range around the 50 th percentile level relative to our peer group.

 

 

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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.  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 defined market for skills and experience necessary to execute our business strategy.
Annual Incentive Bonuses		Performance-related annual cash incentives earned based on our 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 performance and reward our executive officers for individual performance during the year and for contributing to our financial success.  Amounts provided as incentive bonuses are also designed to provide competitive total direct 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 2012 and going forward, 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, with 50% thereof to vest ratably over four years and the other 50% 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 and all other regular full-time employees.		Provide our executive officers and other employees 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 and all other regular full-time employees.		Provide benefits to meet the health and wellness needs of our executive officers and other employees 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, each executive officer’s personal performance, length of service with us and previous work experience.  For 2012 and going forward, 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 CEO 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 CEO.

 

Actions Taken With Respect to Base Salaries.   With two exceptions, there were no base salary increases for the executive officers for 2012.  The exceptions were the initial base salary for Mr. Harris provided for in his employment agreement which took effect at the time of his employment in August 2012 and a base salary increase for Mr. Gardner that took effect in April 2012.  Continuing in 2013, consistent with the compensation freeze generally in effect for employees of the Company, no base salary increases have been provided for the executive officers.  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 2012 were not and for 2013 have not been benchmarked at any particular level relative to our peer group.  The base salaries of the executive officers for 2012 and 2013 are reflected in the table below.

 

 

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Name		2012 Base Salary (1)				2013 Base Salary (2)
Charles C. Ungurean		$	500,000			$	500,000
Bradley W. Harris			300,000				300,000
Jeffrey M. Gutman			270,000			N/A
Daniel M. Maher			270,000				270,000
Gregory J. Honish			210,000				210,000
Thomas T. Ungurean			275,000			N/A
Michael B. Gardner			170,000				170,000

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(1)

There were no changes in base salaries at the start of 2012 or during 2012, except that the base salary for Mr. Harris represented the initial base salary for him under his employment agreement upon his commencement of employment in August 2012, and the base salary for Mr. Gardner was increased by $5,000 to $170,000 effective in April 2012.

 

(2)

There have been no changes in base salaries for 2013.  No 2013 base salaries are shown for Messrs. Gutman and Thomas Ungurean as they were not executive officers at the start of 2013.  Mr. Gutman terminated his employment and ceased to be an executive officer on October 1, 2012 and Mr. Thomas Ungurean resigned his position as an executive officer on June 30, 2012 although he continues to be employed in a different role.

 

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 CEO 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 CEO (and Mr. Maher 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 specified in the employment agreements, as a percentage of annual base salaries, were 100% for Messrs. Charles Ungurean and Thomas Ungurean, 75% for Messrs. Gutman, Maher and Honish and 50% for Mr. Gardner for 2012, and are 125% for Mr. Charles Ungurean, 100% for Messrs. Harris, Maher and Honish and 50% for Mr. Gardner for 2013.

 

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 2012 and going forward 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 2012 and 2013:

 

·

the level of achievement of certain financial performance goals for the year (our budgeted distributable cash flow for 2012 and our budgeted Adjusted EBITDA less maintenance and mine development capital expenditures for 2013), with a weighting as a percentage of the target bonus amounts at the target level for such factor of 60% (except 35% for Mr. Gardner) for 2012 and 50% (except 35% for Mr. Gardner) for 2013;

 

 

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·

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 2012 and 2013; and

 

·

the discretionary bonus amount determined based on personal performance criteria, with a weighting as a percentage of the target bonus amounts of 25% (except 50% for Mr. Gardner) for 2012 and 35% (except 50% for Mr. Gardner) for 2013.

 

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 because 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.

 

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 2012.

 

Name		Financial Performance (1)				Safety (2)				Personal Performance (3)				Total
Charles C. Ungurean (4)		$	—			$	150,000			$	125,000			$	275,000
Bradley W. Harris (5)
Jeffrey M. Gutman (6)
Daniel M. Maher (7)
Gregory J. Honish (8)			—				47,250				55,250				102,500
Thomas T. Ungurean (9)
Michael B. Gardner (10)			—				25,500				42,500				68,000

 

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(1)

The minimum level of achievement for Company financial performance was not achieved.  Accordingly, there were no amounts awarded relating to Company financial performance.

 

(2)

Safety is considered of paramount importance to the Company, and the Company is very pleased with the strong safety performance for 2012.  This performance resulted in achievement in excess of the maximum level of achievement for safety, and accordingly resulted in amounts awarded relating to safety at the maximum level for that factor.

 

(3)

Messrs. Charles Ungurean and Gardner 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.  Mr. Honish was determined to have exceeded the target level of personal performance and accordingly was awarded an amount relating to personal performance above the target level for that factor.

 

(4)

The annual incentive bonus award for Mr. Charles Ungurean represented 55% of his base salary and also 55% of his target bonus amount.

 

(5)

Mr. Harris was employed by the Company in August of 2012 and was not eligible for an annual incentive bonus for 2012.  In lieu thereof, he received an employment inducement bonus and a guaranteed bonus for the partial year period he was employed during 2012.

 

(6)

Mr. Gutman terminated his employment and ceased to be an executive officer on October 1, 2012 and accordingly was not eligible for any annual incentive bonus for 2012.

 

 

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(7)

At his request, Mr. Maher was not considered for an annual incentive bonus for 2012.  For 2012, he was eligible for the second and final year of employment inducement bonuses which offset any annual incentive bonus award for him.  Assuming an award for personal performance at the target award level, the annual incentive bonus award for Mr. Maher would have been $111,375, an amount which would have been fully offset by his employment inducement bonuses of $135,000 for 2012.

 

(8)

The annual incentive bonus award for Mr. Honish represented 49% of his base salary and 65% of his target bonus amount.

 

(9)

Mr. Thomas Ungurean resigned his position as an executive officer on June 30, 2012 and accordingly was not eligible for an annual incentive bonus for 2012.

 

(10)

The annual incentive bonus award for Mr. Gardner represented 40% of his base salary and 80% of his target bonus amount.

 

Bonuses for 2012.   Including the annual cash incentive bonuses for 2012 described in the table above, our executive officers received bonuses for 2012 in the amounts set forth in the table below.

 

Name		2012 Bonus
Charles C. Ungurean (1)		$	275,000
Bradley W. Harris (2)			162,500
Jeffrey M. Gutman (3)			—
Daniel M. Maher (4)			135,000
Gregory J. Honish (1)			102,500
Thomas T. Ungurean (5)			25,000
Michael B. Gardner (1)			68,000

 

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(1)

The entire bonus amounts for Messrs. Charles Ungurean, Honish and Gardner are their annual incentive bonus awards previously described.

 

(2)

The bonus amount for Mr. Harris consists of an employment inducement bonus of $50,000 and a guaranteed bonus of $112,500 payable relating to his initial partial year period of employment in 2012.

 

(3)

Mr. Gutman terminated his employment and ceased to be an executive officer on October 1, 2012 and accordingly was not eligible for any bonus.

 

(4)

The bonus amount for Mr. Maher consists of employment inducement bonuses of $135,000.

 

(5)

Mr. Thomas Ungurean resigned his position as an executive officer on June 30, 2012 and accordingly was not eligible for any bonus payable to him as an executive officer.  After such resignation Mr. Thomas Ungurean continues to be an employee, and the 2012 bonus amount paid to him in December 2012 was a discretionary bonus paid to him as an employee and not as an executive officer.

 

Retention and Other Bonuses.   Messrs. Harris, Maher and Honish are each eligible for retention bonuses in the aggregate amount of their base salaries, 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 is eligible for a retention bonus of $50,000 payable for and subject to his continued employment through May 15, 2013.  The purpose of the retention bonuses 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.  Mr. Harris is further eligible for a transaction bonus in the amount of his base salary in the event a change of control transaction occurs at any time on or before December 31, 2013.

 

 

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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.

 

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 2012, 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.

 

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 exception that equity-based awards will 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 2012.   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, 2013 in the amounts set forth in the table below.  These awards, although granted in 2013, were intended as a part of the named executive officers’ 2012 compensation and were granted to reward the named executive officers for performance in 2012.  Messrs. Gutman and Thomas Ungurean were not eligible for these awards because they ceased to be executive officers before the end of 2012.  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 2012, 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).  In addition, in connection with his employment by us, Mr. Harris received an award of 100,000 phantom units in August 2012 pursuant to the terms of his employment agreement, with 25% thereof vesting at the time of award and the remaining 75% thereof vesting in three equal installments on March 31, 2013 and the next two anniversaries of such date.

 

 

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Name		Value of Phantom Units (1)				Number of Phantom Units
Charles C. Ungurean		$	500,017				113,126
Bradley W. Harris (2)			1,208,021				167,878
Jeffrey M. Gutman (3)			—				—
Daniel M. Maher			270,009				61,088
Thomas T. Ungurean (3)			—				—
Gregory J. Honish			210,003				47,512
Michael B. Gardner			85,005				19,232

 

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(1)

Except as indicated in footnote (2) below, the number of phantom units was determined based on the closing trading price of our common units on December 31, 2012, 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.

 

(2)

The portion of the phantom units related to 2012 performance was 67,878 units valued at the aggregate amount of $300,021 based on the closing trading price of our common units on December 31, 2012, with the remainder of the phantom units granted in connection with his employment as described above consisting of 100,000 units valued at $908,000 based on the closing trading price of our common units on August 31, 2012.

 

(3)

Messrs. Gutman and Thomas Ungurean were not eligible for awards because they ceased to be executive officers before the end of 2012.

 

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) savings plan.  The plan allows executive officers and other employees to contribute compensation for retirement up to IRS imposed limits (for 2012, $17,000 for participants age 49 and under and $22,500 for participants age 50 and over), 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.  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.  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 company-owned automobiles for Messrs. Charles Ungurean and Thomas 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.

 

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.

 

 

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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, 2014.  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, 2012 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.

 

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 President and Chief Executive Officer	2012   2011   2010	511,155   511,155   432,212	275,000   104,895   253,846	526,688   92,227	13,835   13,541   13,691	1,326,678   720,873   699,749
Bradley W. Harris Senior Vice President, Chief Financial Officer and Treasurer	2012   2011   2010	108,642	162,500	908,000	3,090	1,182,052
Jeffrey M. Gutman former Senior Vice President, Chief Financial Officer and Treasurer	2012   2011   2010	219,001   280,270   265,423	42,525   141,500	270,038   47,574   295,883	157,168   18,550   14,820	646,207   388,919   717,626

 

 

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Name and Principal Position

Year

Salary ($)

Bonus ($) (1)

Unit Awards ($) (2)

All Other Compensation ($) (3)

Total ($)

Daniel M. Maher Senior Vice President, Chief Legal Officer and Secretary	2012   2011   2010	277,847   265,846	135,000   201,250	270,038   448,463	19,069   15,332	701,954   930,890
Gregory J. Honish Senior Vice President, Operations	2012   2011   2010	220,040   214,851   166,193	102,500   33,075   91,580	210,054   80,851	10,083   10,083   7,149	542,677   338,860   264,922
Thomas T. Ungurean former Senior Vice President, Equipment, Procurement and Maintenance	2012   2011   2010	177,117   285,290   247,981	25,000   57,692   141,057	289,728   50,742	11,229   11,172   11,322	503,074   404,377   400,360
Michael B. Gardner Vice President – Legal, General Counsel – Regulatory/Environmental and Assistant Secretary	2012   2011   2010	186,144   174,774   154,404	68,000   74,250   76,988	82,545   27,502	17,683   6,792   6,802	354,372   283,318   238,194

 

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(1)

The 2012 bonus amounts for Messrs. Charles Ungurean and Honish reflect bonuses paid in early 2013 that relate to services performed in 2012.  The 2012 bonus amount for Mr. Harris consists of an employment inducement bonus of $50,000 paid in 2012 and a guaranteed bonus of $112,500 paid in early 2013 that relates to services performed in 2012.  The 2012 bonus amount for Mr. Maher consists of employment inducement bonuses of $135,000 paid in 2012.  Disregarding the employment inducement bonuses, Mr. Maher would have had a 2012 bonus of $111,375 under the bonus plan in effect for all of our executive officers, and since such bonus amount is offset by the employment inducement bonuses amount there was no additional bonus payment to Mr. Maher under such plan.  The 2012 bonus amount for Mr. Gardner was paid in partly in 2012 and partly in 2013 and relates to services performed in 2012.

 

(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 2012 for each of the named executive officers except Mr. Gardner and in January 2012 only for Mr. Gardner.  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.

 

(3)

2012 amounts shown include contributions being made to our 401(k) savings plan for each of the named executive officers with respect to services performed in 2012, payments made in 2012 with respect to life insurance benefits provided to each of the named executive officers, a holiday-related allowance paid in 2012 to each of the named executive officers, the taxable portion of automobile allowances paid to Messrs. Harris, Gutman, Maher and Gardner, and the dues paid for Messrs. Charles Ungurean, Harris, Gutman and Maher for a dining and athletic club facility located in the same building as our executive offices.  Also for Mr. Gutman, the 2012 amount shown includes a payment for the value of unused vacation and a severance payment of $135,000 following his termination of employment.  For each of Messrs. Charles Ungurean and Thomas Ungurean, who are provided company-owned automobiles primarily for business use (with personal use being limited to usage for commuting purposes), the amounts shown for 2012 also include the cost to us of providing an automobile to them for their use for the estimated personal usage portion thereof for commuting purposes (10% of the total cost in the case of Mr. Charles Ungurean and 5% of the total cost in the case of Mr. Thomas Ungurean) in the amount of $1,826 and $1,008, respectively.

 

Grants of Plan-Based Awards for 2012

 

The following table provides information regarding grants of plan-based awards to named executive officers during the year ended December 31, 2012.

 

 

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Name		Grant Date		All Other Unit Awards: Number of Units (#)				Grant Date Fair Value of Unit Awards ($) (1)
Charles C. Ungurean President and Chief Executive Officer		1/1/12 3/2/12			18,408 31,252				276,672 250,016
Bradley W. Harris Senior Vice President, Chief Financial Officer and Treasurer		8/31/12			100,000				908,000
Jeffrey M. Gutman former Senior Vice President, Chief Financial Officer and Treasurer		1/1/12 3/2/12			8,984 16,876				135,030 135,008
Daniel M. Maher Senior Vice President, Chief Legal Officer and Secretary		1/1/12 3/2/12			8,984 16,876				135,030 135,008
Gregory J. Honish Senior Vice President, Operations		1/1/12 3/2/12			6,988 13,128				105,030 105,024
Thomas T. Ungurean former Senior Vice President, Equipment, Procurement and Maintenance		1/1/12 3/2/12			10,128 17,188				152,224 137,504
Michael B. Gardner Vice President-Legal, General Counsel-Regulatory/Environmental and Assistant Secretary		1/1/12			5,492				82,545

 

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(1)

Amounts shown are based on the grant date fair market value of our common units of $15.03 for units granted on January 1, 2012, $8.00 for units granted on March 2, 2012 and $9.08 for units granted on August 31, 2012.

 

Outstanding Equity-Based Awards at December 31, 2012

 

The following table provides information regarding outstanding equity-based awards held by the named executive officers as of December 31, 2012.  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 Messrs. Gutman and Maher.  None of the named executive officers hold outstanding option awards.

 

 

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		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 President and Chief Executive Officer			52,499								232,046
Bradley W. Harris Senior Vice President, Chief Financial Officer and Treasurer			75,000								331,500
Jeffrey M. Gutman (4) former Senior Vice President, Chief Financial Officer and Treasurer
Daniel M. Maher Senior Vice President, Chief Legal Officer and Secretary			34,070				4.758029				150,589 8,872
Gregory J. Honish Senior Vice President, Operations			22,605								99,914
Thomas T. Ungurean former Senior Vice President, Equipment, Procurement and Maintenance			28,878								127,641
Michael B. Gardner Vice President – Legal, General Counsel – Regulatory/Environmental and Assistant Secretary			6,338								28,014

 

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(1)

As to Messrs. Charles Ungurean, Honish and Thomas Ungurean, a portion of the units (2,839 for Mr. Charles Ungurean, 2,489 for Mr. Honish and 1,562 for Mr. Thomas Ungurean) vest in equal amounts on each of March 31, 2013 and the next two anniversaries thereof, a further portion of the units (18,408 for Mr. Charles Ungurean, 6,988 for Mr. Honish and 10,128 for Mr. Thomas Ungurean) vest in equal amounts on each of March 31, 2013 and the next three anniversaries thereof, and the remainder of the units (31,252 for Mr. Charles Ungurean, 13,128 for Mr. Honish and 17,188 for Mr. Thomas Ungurean) vest in two stages based upon achievement of certain performance criteria.  As to Mr. Harris, the units vest in equal amounts on each of March 31, 2013 and the next two anniversaries thereof.  As to Mr. Maher, 8,210 of his units vest in equal amounts on each of January 1, 2013 and January 1, 2014, 8,984 units vest in equal amounts on March 31, 2013 and the next three anniversaries thereof, and the remaining 16,876 units vest in two stages based upon achievement of certain performance criteria.  As to Mr. Gardner, 846 of his units vest in equal amounts on each of March 31, 2013 and the next two anniversaries thereof, and the remaining 5,492 units vest in equal amounts on March 31, 2013 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, 2013 and the next two anniversaries thereof.

 

(3)

For phantom units, based on the closing price of our common units of $4.42 on December 31, 2012; 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, 2012, as determined in accordance with FASB ASC Topic 718.

 

(4)

Mr. Gutman forfeited all of his unvested phantom units and Class B units upon his termination of employment on October 1, 2012, and accordingly he had no unvested phantom units or Class B units.

 

In addition to these outstanding equity-based awards at December 31, 2012, there were additional equity-based awards on January 1, 2013 as described above under “Equity-Based Awards – Equity-Based Awards for 2012 .”

 

 

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Units Vested in 2012

 

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 2012.  None of the named executive officers held or exercised any stock options in 2012.

 

Name		Number of Units Acquired on Vesting (#)		Value Realized on Vesting ($)
Charles C. Ungurean President and Chief Executive Officer (1)		947 (1)		8,050 (1)
Bradley W. Harris Senior Vice President, Chief Financial Officer and Treasurer (1)		25,000 (2)		227,000 (2)
Jeffrey M. Gutman former Senior Vice President, Chief Financial Officer and Treasurer (1)		7,283 (3) 1.504010 (4)		106,447 (3) 3,783 (4)
Daniel M. Maher Senior Vice President, Chief Legal Officer and Secretary (1)		4,105 (5) 1.586010 (6)		61,698 (5) 7,498 (6)
Gregory J. Honish Senior Vice President, Operations (1)		830 (1)		7,055 (1)
Thomas T. Ungurean former Senior Vice President, Equipment, Procurement and Maintenance (1)		521 (1)		4,428 (1)
Michael B. Gardner Vice President – Legal and General Counsel – Regulatory/Environmental (1)		283 (1)		2,406 (1)

 

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(1)

These units vested on March 31, 2012, and the value realized amount reflects a unit value of $8.50 per unit on such vesting date.

 

(2)

These units vested on August 31, 2012, and the value realized amount reflects a unit value of $9.08 per unit on such vesting date.

 

(3)

Of these units, 6,821 units vested on January 1, 2012 and 462 units vested on March 31, 2012, and the value realized amount reflects a unit value of $15.03 and $8.50 per unit, respectively, on each such vesting date.

 

(4)

Of these Class B units of our general partner, 0.009210 units vested on January 1, 2012 and 1.494800 units vested on July 19, 2012, and the value realized amount reflects an estimate of the total fair market values of such units as of such dates, as determined in accordance with FASB ASC Topic 718.

 

(5)

These units vested on January 1, 2012, and the value realized amount reflects a unit value of $15.03 per unit on such vesting date.

 

(6)

These units vested on January 1, 2012, 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.

 

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, 2012.

 

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, 2012.

 

 

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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.  The employment agreements for Messrs. Gutman and Thomas Ungurean terminated on October 1, 2012 (by reason of Mr. Gutman’s termination of employment) and June 30, 2012 (in connection with Mr. Thomas Ungurean’s resignation as an officer), respectively. For all of our other named executive officers, the terms of their employment agreements run through December 31, 2014.  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. Charles 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 elected 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 these severance benefits paid by our general partner are subject to reimbursement by us to our general partner.

 

“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, or (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. Charles 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. Charles Ungurean agreed that he would not compete with us in the coal mining business in Illinois, Kentucky, Ohio, Pennsylvania, West Virginia and Virginia until 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, 2012, assuming each named executive officer had terminated employment on December 31, 2012.

 

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		$	14,186				14,186
		Total			14,186				1,014,186				1,000,000
Bradley W. Harris		Cash severance							600,000				600,000
		Benefit Continuation							12,442				12,442
		Total							612,442				612,442
Jeffrey M. Gutman (1)		Cash severance							—				—
Daniel M. Maher		Cash severance							540,000				540,000
Gregory J. Honish		Cash severance							420,000				420,000
Thomas T. Ungurean (1)		Cash severance							—				—
Michael B. Gardner		Cash severance							170,000				170,000

 

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(1)

Messrs. Gutman and Thomas Ungurean terminated employment and resigned as an executive officer, respectively, in 2012, and accordingly had no severance benefits in effect at the end of 2012.

 

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 in control with respect to us or our general partner had occurred on December 31, 2012, 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 (52,499 units for Mr. Charles Ungurean having an aggregate market value as of such date of $232,046, 75,000 units for Mr. Harris having an aggregate market value as of such date of $331,500, 34,070 units for Mr. Maher having an aggregate market value as of such date of $150,589, 22,605 units for Mr. Honish having an aggregate market value as of such date of $99,914, 28,878 units for Mr. Thomas Ungurean having an aggregate market value as of such date of $127,641 and 6,338 units for Mr. Gardner having an aggregate market value as of such date of $28,014, in each case with the value being based on the closing price of our common units of $4.42 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, 2012, Mr. Maher would have been entitled to accelerated vesting with respect to the 4.758029 such Class B units that were unvested on such date at an estimated aggregate fair market value as of such date of $8,872 determined in accordance with FASB ASC Topic 718.  Mr. Gutman, by reason of his termination of employment on October 1, 2012, forfeited all of his unvested phantom units and Class B units at that time, and accordingly would not have been entitled to any accelerated vesting of them in the event of a change of control occurring on December 31, 2012.

 

 

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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 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 ($1,000 through 2012 and increased to $2,000 in 2013 to take into account the fact that these meetings require a two-day rather than one-day commitment due to travel to and from the meetings); 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 2012

 

The following table sets forth the compensation paid to our non-employee directors for the year ended December 31, 2012, as described above.  None of our non-employee directors held any unvested units as of December 31, 2012.

 

Name		Fees ($) (1)				Unit Awards ($) (2)				Total ($)
Gerald A. Tywoniuk		$	96,500			$	50,016			$	146,516
Peter B. Lilly		$	—			$	136,013			$	136,013
Robert J. Messey		$	66,500			$	50,016			$	116,516

 

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(1)

The amounts in this column represent the fees paid to the directors in 2012.  In the case of Messrs. Tywoniuk and Messey, all of the fees were paid in cash.  In the case of Mr. Lilly, he elected to receive units in lieu of receiving payment of such compensation in cash, and those units are thus instead included in the “Unit Awards ($)” column. Mr. Lilly received in lieu of such compensation in cash (a) 2,529 units which were granted and vested on March 31, 2012 at a  market value based on the closing price of $8.50 per unit on such date; (b) 3,037 units which were granted and vested on June 30, 2012 at a market value based on the closing price of $7.74 per unit on such date; (c) 2,140 units which were granted and vested on September 30, 2012 at a market value based on the closing price of $9.11 per unit on such date; and (d) 4,864 units which were granted and vested on December 31, 2012 at a market value based on the closing price of $4.42 per unit on such date.

 

(2)

The amounts in this column represent the value of unit awards made to directors under our LTIP in 2012, including in the case of Mr. Lilly the units awards described in footnote (1) above which he elected to receive in lieu of payment of fees for his service (the “Lilly Fees Units”). For each of Messrs. Tywoniuk, Lilly and Messey, and excluding the Lilly Fees Units, (a) 1,471 units were granted and vested on March 31, 2012 and their market value is based on the closing price of $8.50 per unit on such date; (b) 1,615 units were granted and vested on June 30, 2012 and their market value is based on the closing price of $7.74 per unit on such date; (c) 1,373 units were granted and vested on September 30, 2012 and their market value is based on the closing price of $9.11 per unit on such date; and (d) 2,829 units were granted and vested on December 31, 2012 and their market value is based on the closing price of $4.42 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 March 25, 2013 (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.

 

 

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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 AIM.  The class B units of our general partner are owned 67% by Daniel M. Maher, our Senior Vice President, Chief Legal Officer and Secretary, and 33% 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.

 

The percentage of units beneficially owned is based on a total of 10,475,237 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				6.8	%			6,813,160				66.3	%			36.2	%
C&T Coal, Inc. (3)			360,882				3.4	%			3,467,220				33.7	%			18.4	%
Advisory Research, Inc. (4)			1,198,175				11.4	%			—				—				5.8	%
George E. McCown (1)(2)(5)			709,143				6.8	%			6,813,160				66.3	%			36.2	%
Brian D. Barlow (2)			—				—				—				—				—
Matthew P. Carbone (1)(2)(5)			709,143				6.8	%			6,813,160				66.3	%			36.2	%
Gerald A. Tywoniuk (3)(7)			17,135				*				—				—				*
Peter B. Lilly (3)(7)			40,608				*				—				—				*
Robert J. Messey (3) (6)(7)			23,993				*				—				—				*
Charles C. Ungurean (3)(8)(9)			367,377				3.5	%			3,467,220				33.7	%			18.5	%
Thomas T. Ungurean (3)(8)(10)			364,456				3.5	%			3,467,220				33.7	%			18.5	%
Bradley W. Harris (3)(11)			41,278				*				—				—				*
Gregory J. Honish (3)(12)			14,251				*				—				—				*
Daniel M. Maher (3)(13)			9,489				*				—				—				*
Michael B. Gardner (3)(14)			11,491				*				—				—				*
All directors and executive officers as a group (consisting of 13 persons)			1,252,660				12.0	%			10,280,380				100.0	%			55.6	%

 

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

 

 

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(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 Two Prudential Plaza, 180 N. Stetson Avenue, suite 5500, Chicago, Illinois 60601.

 

(5)

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

 

(6)

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.

 

(7)

The common units shown for Messrs. Tywoniuk, Lilly and Messey include common units which will vest and be issued to them on March 31, 2013.  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, 2013.  Each of them will have units having a value of $12,500 at such closing price (estimated at 5,000 units based on an estimated closing price of $2.50 per unit) issued to him.

 

(8)

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.

 

(9)

Does not include 160,077 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.

 

(10)

Does not include 25,825 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.

 

(11)

Does not include 117,878 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 67,541 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 88,807 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 23,915 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.

 

 

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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 2,056,075 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.

 

The following table summarizes the number of securities remaining available for future issuance under our LTIP as of December 31, 2012.

 

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)			—			$	—				1,739,068	(2)
Equity compensation plans not approved by security holders			—				—				—
Total			—			$	—				1,739,068	(2)

 

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(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 2,056,705 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 257,963 outstanding phantom units.

 

 

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ITEM 13.              CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS, AND DIRECTOR INDEPENDENCE

 

At December 31, 2012, C&T Coal owns 360,882 common units and 3,467,220 subordinated units representing a combined 18.1% limited partner interest in us, and AIM Oxford owns 709,143 common units and 6,813,160 subordinated units representing a combined 35.6% 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, the Senior Vice President, Equipment, Procurement and Maintenance of our general partner until his resignation effective June 30, 2012, 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 an ownership interests in AIM.  Jeffrey M. Gutman was the Senior Vice President, Chief Financial Officer and Treasurer of our general partner until his resignation effective October 1, 2012, 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 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 2012, 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 scheduled to expire on December 31, 2011.  During July 2011, we concluded negotiations with Tunnell Hill for an early termination of the services agreement 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.  Under the leasing arrangement, we received $23,700 per month for rental of the equipment, and Tunnell Hill 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.  Following the lease term, Tunnell Hill exercised its option to purchase the leased equipment.  In the first quarter of 2012, 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.  We continue to sell clay and small quantities of coal to Tunnell Hill which totaled $181,000 in 2012.

 

 

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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 an airplane from Zanesville Aviation located in Zanesville, Ohio.  C&T Coal owns an airplane that it leases to Zanesville Aviation and that Zanesville Aviation uses in providing chartering services to its customers, including us.  During the years of 2012, 2011 and 2010, we paid Zanesville Aviation an aggregate of $146,000, $178,000, and $283,000, 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.  We will provide a copy of the code of business conduct and ethics to any person without charge upon request.

Further information required for this item is provided in “Item 1. Business — Overview,” “Item 10. Directors, Executive Officers and Corporate Governance” and Note 21: Related Party Transactions included in the notes to the audited 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 Year Ended December 31,
Name		2012				2011
Audit fees (1)		$	383,000			$	387,000
Audit-related fees (2)			—				16,000
Tax fees (3)			—				86,000
All other fees (4)			—				—
Total		$	383,000			$	489,000

 

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(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.

(2)

Includes fees and expenses related to consultations concerning financial accounting and reporting standards and the S-3 filed with the SEC in 2011.

(3)

Includes fees and expenses related to professional services for tax compliance, tax advice and tax planning.

(4)

Consists of fees and expenses for services other than services reported above.

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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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: April 1, 2013

 

	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/ BRA DLEY 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 29, 2013
George E. McCown
/s/ CHARLES C. UNGUREAN		Director, President and Chief		March 29, 2013
Charles C. Ungurean		Executive Officer (principal executive officer)
/s/ BRADLEY W. HARRIS		Senior Vice President, Chief Financial		March 29, 2013
Bradley W. Harris		Officer and Treasurer (principal financial officer)
/s/ DENISE M. MAKSIMOSKI		Senior Director of Accounting		March 29, 2013
Denise M. Maksimoski		(principal accounting officer)
/s/ BRIAN D. BARLOW		Director		March 29, 2013
Brian D. Barlow
/s/ MATTHEW P. CARBONE		Director		March 29, 2013
Matthew P. Carbone
/s/ PETER B. LILLY		Director		March 29, 2013
Peter B. Lilly
/s/ ROBERT J. MESSEY		Director		March 29, 2013
Robert J. Messey
/s/ GERALD A. TYWONIUK		Director		March 29, 2013
Gerald A. Tywoniuk

 

 

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