Item 1. Business

Overview

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

We operate in a single business segment and have four operating subsidiaries, Oxford Mining Company, LLC ("Oxford Mining"), Oxford Mining Company-Kentucky, LLC (“Oxford Mining Kentucky”), Westmoreland Kemmerer Fee Coal Holdings, LLC ("WKFCH") and Harrison Resources, LLC ("Harrison Resources"). Our Oxford Mining operating subsidiaries participate primarily in the business of utilizing surface mining techniques to mine domestic coal and prepare it for sale to our customers or lease our controlled coal reserves to others to mine. Our WKFCH and Harrison Resources operating subsidiaries own and hold coal reserves. WKFCH’s coal reserves are leased to Westmoreland Coal Company ("WCC") to which WKFCH earns a per ton coal royalty. Harrison coal reserves are surfaced mined and marketed by Oxford Mining. Oxford Mining Kentucky is an inactive operating subsidiary holding coal reserves in the Illinois Basis for which surface mining operation ceased in December 2013.

As of December 31, 2014 , management estimates that we owned or controlled approximately 106.5 million tons of coal reserves, of which we have leased or subleased 54.7 million tons of reserves to others. The estimates are based on an initial evaluation, as well as subsequent acquisitions, dispositions, depletion of reserves, changes in available geological or mining data and other factors.

For the year ended December 31, 2014 , we sold 5.6 million tons of coal, compared to 6.6 million tons for the year ended December 31, 2013 , of which approximately 5.5 million and 6.1 million tons, respectively, were produced from our mining activities, and 0.1 million and 0.5 million tons, respectively, were purchased through brokered coal contracts (coal purchased from third parties for resale), at an average purchase price of $26.33 and $49.00 , respectively, for the years ended December 31, 2014 and 2013 . For the year ended December 31, 2014 , we derived approximately 99.1% of our total coal revenues from sales to our ten largest coal customers, with the following top three coal customers and their affiliates accounting for approximately 87.5% of our coal revenues for that period: American Electric Power Company, Inc. ( 56.7% ); FirstEnergy Corp. ( 16.5% ); and East Kentucky Power Cooperative ( 14.3% ).

In December 2014, WCC, a Delaware corporation , completed its acquisition of our general partner, and contributed certain royalty bearing coal reserves to us in exchange for common units. In connection with the transaction, we changed our name, restructured our limited partnership agreement, made a one-time "25% unit dividend" as a special distribution to our public common unitholders, and refinanced our credit facilities.

Westmoreland Coal Company Transactions

Acquisition of Oxford Resources GP, LLC

On December 31, 2014, pursuant to a Purchase Agreement dated October 16, 2014, WCC acquired, for $33.5 million in cash, 100% of the equity of our GP from (i) the holders of all of our GP’s outstanding Class A Units, AIM Oxford Holdings, LLC (“AIM”) and C&T Coal, Inc. (“C&T”), (ii) the holders of all of our GP’s outstanding Class B Units, certain present and former executives of our GP, and (iii) the holders of all of the outstanding warrants for our GP’s Class B Units, certain affiliates of our former second lien term loan lenders (the “Warrantholders”). At the same time, WCC also acquired, for no additional consideration, (i) 100% of the Partnership’s outstanding subordinated units from AIM and C&T which were then converted to liquidation units, and (ii) 100% of the Partnership’s outstanding warrants for subordinated units from the Warrantholders, which warrants were then canceled by WCC.

Contribution of Kemmerer Mine Coal Reserves

In December 2014, pursuant to a contribution agreement, WCC contributed to us 100% of the membership interests in WKFCH. WKFCH holds fee simple interests in 30.4 million tons of coal reserves and related surface lands at WCC’s Kemmerer Mine in Lincoln County, Wyoming. Such contribution was made in exchange for 4,512,500 post-reverse split common units, resulting in WCC holding 79.0% of our outstanding limited partner units at March 3, 2015 , after taking into account the above-mentioned "25% unit dividend."

In connection with this contribution, WKFCH entered into a coal mining lease with respect to these coal reserves with a subsidiary of WCC pursuant to which we will earn a per ton royalty as these coal reserves are mined. Through the coal leasing arrangement, the mining of the Kemmerer fee coal reserves are expected to generate $5.8 million in average annual royalties over the next three years, with a minimum royalty payment of $1 million per quarter from the start of 2015 through December 31, 2020 and $0.5 million per quarter thereafter through December 31, 2025.

Name Changes

As part of the transactions with WCC, we changed our name from Oxford Resource Partners, LP to Westmoreland Resource Partners, LP. Our GP also changed its name from Oxford Resources GP, LLC to Westmoreland Resources GP, LLC. Westmoreland Resource Partners, LP is a Delaware limited partnership listed on the New York Stock Exchange (the “NYSE”) under the ticker symbol “WMLP.”

Restructuring of the Partnership

On December 23, 2014 we received unitholder approval for the amendment and restatement of, and effective December 31, 2014 we amended and restated, our limited partnership agreement to, among other things:

Special Distribution to Pu blic Unitholders

Following the WCC transactions, we made a one-time special distribution to our public unitholders in January 2015. The distribution was made on a pro rata basis, and consisted of a "25% unit dividend" of 0.2 million in additional post-reverse split common units.

Debt Refinancing

In connection with the WCC transactions, we entered into a new credit facility under a Financing Agreement (the “2014 Financing Agreement”) with the lenders party thereto and U.S. Bank National Association as Administrative and Collateral Agent to replace our existing $175 million credit facility. The new credit facility consists of a $175 million term loan, with an option for an additional up to $120 million in term loans for acquisitions if requested by us and approved by the issuing lenders. The 2014 Financing Agreement matures in December 2018 and contains customary financial and other covenants. It also permits distributions to our unitholders under specified circumstances. Borrowings under the 2014 Financing Agreement are secured by substantially all of our physical assets. Proceeds of the new credit facility were used to retire our then existing first and second lien credit facilities and to pay fees and expenses related to our new credit facility, with the limited amount of remaining proceeds being available as working capital.

Operations

As of December 31, 2014 , we operated 13 active surface mines and managed these mines as six mining complexes located in eastern Ohio. These mining facilities include two preparation plants, both of which receive, wash, blend, process and ship coal produced from one or more of our 13 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 which we move among our mining complexes, as necessary, and two highwall miner systems. Additionally, in 2014 we contracted with a third party to operate two additional highwall miner systems owned by the third party.

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

As of December 31, 2014 , we owned and/or controlled 106.5 million tons of proven and probable coal reserves, of which 51.8 million tons were associated with our surface mining operations, 30.4 million tons were leased to a subsidiary of WCC 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 2014 , we obtained control of 31.9 million tons of proven and probable coal reserves.

The following table summarizes our mining complexes, our coal production for the year ended December 31, 2014 and our coal reserves as of December 31, 2014 :

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, 2014 .

We operate six surface mining complexes in Northern Appalachia, substantially all of which are located in eastern Ohio. For the year ended December 31, 2014 , our mining complexes in Northern Appalachia produced an aggregate of 5.6 million tons of thermal coal. The following table provides summary information regarding our mining complexes in Northern Appalachia for the years indicated.

								Number of Active Mines at December 31,			Tons Produced for the Year Ended
		Transportation Facilities Utilized				Transportation Method   (1)					December 31,
Mining Complex		River Terminal		Rail Loadout				2014			2014			2013			2012
											(in millions)
Cadiz		Bellaire		Cadiz		Barge, Rail, Truck		4			3.1			2.6			2.6
Tuscarawas		—		—		Truck		4			1.2			1.2			0.7
Plainfield		—		—		Truck		—			—			—			0.4
Belmont		Bellaire		—		Barge, Truck		2			0.4			1.0			1.0
New Lexington		—		New Lexington		Rail, Truck		2			0.7			0.8			0.9
Noble		Bellaire		—		Barge, Truck		1			0.2			0.2			0.2
Total								13			5.6			5.8			5.8

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 Harrison Resources, Daron, Ellis and Sandy Ridge mines. We began mining operations at this mining complex in 2000. Operations at the Cadiz mining complex target the Pittsburgh #8, Redstone #8A and Meigs Creek #9 coal seams. As of December 31, 2014 , the Cadiz mining complex included 7.9 million tons of proven and probable coal reserves. Coal produced from the Cadiz mining complex is trucked either to our Bellaire river terminal on the Ohio River and then transported by barge to the customer, trucked directly to our customer, or trucked to our Cadiz rail loadout facility on the Ohio Central Railroad and then transported by rail to the customer, or trucked to our Strasburg preparation plant then transported by truck to the customer after processing is completed. This mining complex uses the area, contour, auger and highwall miner methods of surface mining. The infrastructure at this mining complex includes three coal crushers, three truck scales and the Cadiz rail loadout. This mining complex produced 3.1 million tons of coal for the year ended December 31, 2014 .

In early October 2014, Oxford Mining entered into a membership interest redemption agreement with Harrison Resources and CONSOL of Ohio LLC (“CONSOL”) under which Harrison Resources redeemed all of CONSOL’s interest in Harrison Resources. Harrison Resources had been a joint venture owned 51% by Oxford Mining and 49% by CONSOL, and as a result of the redemption Oxford Mining owns 100% of Harrison Resources. In connection with the redemption, Harrison Resources acquired 0.9 million tons of coal reserves from a CONSOL affiliate, and also options to purchase an aggregate of 5.6 million additional tons of coal reserves from a CONSOL affiliate. These tons are in addition to the 2.6 million tons of coal reserves already owned by Harrison Resources. Harrison Resources paid total consideration of $3.6 million in these transactions. These transactions were effective as of October 1, 2014.

Tuscarawas Mining Complex

The Tuscarawas mining complex is located in Tuscarawas, Columbiana and Stark Counties, Ohio, and currently consists of the East Canton, Garrett, Hunt and Stillwater 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, 2014 , the Tuscarawas mining complex included 6.0 million tons of proven and probable coal reserves. Coal produced from the Tuscarawas mining complex is transported by truck directly to our customers, our Barb Tipple blending and coal crushing facility or our Strasburg preparation plant. Coal trucked to our Barb Tipple blending and coal crushing facility, our Conesville preparation plant, or our Strasburg preparation 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 and the Strasburg blending facility and preparation plant. This mining complex produced  1.2 million tons of coal for the year ended December 31, 2014 .

Plainfield Mining Complex

The Plainfield mining complex is located in Muskingum, Guernsey and Coshocton Counties, Ohio, and is currently inactive. We began mining operations at this mining complex in 1990. Operations at the Plainfield mining complex target the Middle Kittanning #6 coal seam. As of December 31, 2014 , the Plainfield mining complex included 3.4 million tons of proven and probable coal reserves. When operating, the majority of the coal produced from the Plainfield mining complex is trucked to our Barb Tipple facility for crushing and blending or directly to the customer. Coal trucked to our Barb Tipple facility is transported by truck to the customer after processing is completed. Some of the coal production from this mining complex is trucked to our Conesville preparation plant and then transported by truck to the customer. This mining complex uses contour and highwall miner methods of surface mining. The infrastructure at this mining complex includes our Barb Tipple blending and coal crushing facility, Conesville preparation plant and truck scale. This mining complex produced no coal for the year ended December 31, 2014 .

Belmont Mining Complex

 The Belmont mining complex is located in Belmont County, Ohio, and currently consists of the Speidel and Wheeling Valley mines. We began mining operations at this mining complex in 1999. Operations at the Belmont mining complex target the Pittsburgh #8 and Meigs Creek #9 coal seams. As of December 31, 2014 , the Belmont mining complex included 10.7 million tons of proven and probable coal reserves. Coal produced from this mining complex is primarily transported to our Bellaire river terminal on the Ohio River and then transported by barge to the customer, or by truck to our Barb Tipple facility or our Conesville preparation plant and then transported by truck to the customer. 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 0.4 million tons of coal for the year ended December 31, 2014 .

New Lexington Mining Complex

The New Lexington mining complex is located in Perry, Athens and Morgan Counties, Ohio, and currently consists of the Avondale and New Lexington mines. We began mining operations at this mining complex in 1993. Operations at the New Lexington mining complex target the Lower Kittanning #5 and Middle Kittanning #6 coal seams. As of December 31, 2014 , the New Lexington mining complex included 6.1 million tons of proven and probable coal reserves. Coal produced from the New Lexington mining complex is delivered via off-highway trucks to our New Lexington rail loadout facility on the Ohio Central Railroad where it is then transported by rail to the customer or to our Barb Tipple. Some of the coal production from this mining complex is trucked to our Conesville preparation plant and then transported by truck to the customer. This mining complex uses the area and auger methods of surface mining. The infrastructure at this mining complex includes a coal crusher and the New Lexington rail loadout. This mining complex produced 0.7 million tons of coal for the year ended December 31, 2014 .

Noble Mining Complex

 The Noble mining complex is located in Noble and Guernsey Counties, Ohio, and currently consists of the King-Crum mine. We began mining operations at this complex in 2006. Operations at the Noble mining complex target the Pittsburgh #8 and Meigs Creek #9 coal seams. As of December 31, 2014 , the Noble mining complex included 1.3 million tons of proven and probable coal reserves. Coal produced from this mining complex is trucked to our Bellaire river terminal on the Ohio River or to our Barb Tipple facility. Coal trucked to our Bellaire river terminal is then transported by barge to the customer. Coal trucked to our Barb Tipple blending and coal-crushing facility is transported by truck to the customer after processing is completed. The Noble mining complex uses the area, contour and auger methods of surface mining. This mining complex produced 0.2 million tons of coal for the year ended December 31, 2014 .

⁽¹⁾ Barge means transported by truck to the Island river terminal and then transported to the customer by barge. Truck means transported to the customer by truck. While we sold the Island river terminal in April 2014, we retain the right to ship tons through that dock.

Muhlenberg Mining Complex

The Muhlenberg mining complex, located in Muhlenberg and McLean Counties in western Kentucky, is currently inactive. We began mining operations at this mining complex in October 2009. Operations at the Muhlenberg mining complex targeted the #5, #6, #9, #10, #11, #12 and #13 coal seams of the Illinois Basin. As of December 31, 2014 , the Muhlenberg mining complex included 16.3 million tons of proven and probable coal reserves. Coal produced from this mining complex was usually crushed at the mine site and then trucked to the Island river terminal on the Green River or directly to the customer. Coal trucked to the Island river terminal was then transported to the customer by barge. While we sold the Island river terminal

in April 2014, we retain the right to ship tons through that dock. This mining complex used the area method of surface mining. The infrastructure at this mining complex includes one coal crusher and one truck scales. This mining complex was idled in December 2013 and remained idled throughout year ended December 31, 2014 . We are seeking to sell the remaining Illinois Basin equipment, consisting of a large-capacity shovel and several smaller pieces of equipment, and would consider offers for the remaining coal reserves and/or facilities related to the Illinois Basin operations.

Preparation Plants and Blending Facilities

Depending on coal quality and customer requirements, 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 process that physically separates impurities from the 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. Blending is typically done at one of our four blending facilities:

Roya lty Reve nues

Kemmerer Coal Reserves

Through our subsidiary, WKFCH, we are party to a coal mining lease with a subsidiary of WCC pursuant to which we will earn a per ton royalty as coal reserves owned by WKFCH are mined. Through the coal leasing arrangement, the mining of the Kemmerer fee coal reserves is expected to generate $5.8 million in average annual royalties over the next three years, with a minimum royalty payment of $1 million per quarter from the start of 2015 through December 31, 2020 and $0.5 million per quarter thereafter through December 31, 2025. For the year ended December 31, 2014 , we did not recognize any royalty revenue under the lease for the Kemmerer coal reserves.

Tusky 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 eight 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, 2014 , we did not recognize any royalty revenue on the sublease of the Tusky reserves.

Oil and Gas Reserves

In December 2014, June 2013 and April 2012, we completed the sale of certain oil and gas rights on land in eastern Ohio for $0.2 million , $6.1 million and $6.3 million, respectively, plus future royalties. For the fiscal year ended December 31, 2014 , we generated $0.3 million in royalty revenue from the receipt of oil and gas royalties.

Non-Coal Revenues

Limestone Revenues

At our Daron, Pickens, and Strasburg mines, we remove limestone so that we can access the underlying coal. We sell this limestone to a third party that crushes the limestone before selling it to local governmental authorities, construction companies and individuals. The third party pays us for this limestone based on a percentage of the revenue it receives from the limestone sales. For the year ended December 31, 2014 , we produced and sold 1.6 million tons of limestone, and our revenues included $ 4.7 million in limestone sales. Limestone at our Pickens mine was fully depleted in 2014.

Other Revenues

For the fiscal year ended December 31, 2014 , we generated $21.6 million of other revenues from a variety of other activities in connection with our surface mining operations. This revenue included the following:

For more information regarding our relationships and our former sponsors' relationships with Tunnel Hill Partners, LP, please read Part III, Item 13 - Certain Relationships and Related Transactions, and Director Independence .

Customers

Our primary customers are electric utility companies, predominantly operating in our six-state market area, that purchase coal under long-term coal sales contracts. Substantially all of our customers purchase coal for terms of one year or longer, but we also supply coal on a short-term or spot market basis for some of our customers. For the year ended December 31, 2014 , we derived approximately 99.1% of our total coal revenues from sales to our ten largest customers, with affiliates of the following top three customers accounting for approximately 87.5% of our coal revenues for that period: American Electric Power Company, Inc. ( 56.7% ); FirstEnergy Corp. ( 16.5% ); and East Kentucky Power Cooperative ( 14.3% ). A portion of these sales were facilitated by coal brokers.

Long-term Coal Supply Contracts

As is customary in the coal industry, we enter into long-term supply contracts (one year or greater in duration) with substantially all of our customers. These contracts allow customers to secure an assured supply for their future needs and provide us with greater predictability of sales volumes and prices. For the year ended December 31, 2014 , approximately 96.8% of our coal tons sold were sold under long-term supply contracts. We sell the remainder of our coal through short-term contracts and on the spot market.

The terms of our coal supply contracts result from competitive bidding and extensive negotiations with each customer. Consequently, the terms can vary significantly by contract, and can cover such matters as price adjustment features, price reopener terms, coal quality requirements, quantity adjustment mechanisms, permitted sources of supply, future regulatory changes, extension options, force majeure provisions and termination and assignment provisions. Some long-term contracts provide for a predetermined 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. Some of our contracts also 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 2014 , we spent more than $118.7 million to procure goods and services in support of our operating business activities, excluding capital expenditures. Principal commodities include repair and maintenance parts and services, fuel, explosives, tires and lubricants. Outside suppliers perform a significant portion of our on- and off-site equipment rebuilds and repairs as well as construction and reclamation activities.

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

Competition

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

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 or cash collateral, to secure the bonds. As of December 31, 2014 , we had $9.1 million in cash deposits supporting $34.6 million in reclamation surety bonds. While bonds are issued against reclamation liability for a particular permit at a particular site, collateral posted 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.

Material Effects of Regulation

We are subject to extensive regulation with respect to environmental and other matters by federal, state and local authorities. Federal laws to which we are subject include the Surface Mining Control and Reclamation Act of 1977, or SMCRA, the Clean Air Act, the Clean Water Act, the Toxic Substances Control Act, the Endangered Species Act, the Migratory Bird Treaty Act, the Comprehensive Environmental Response, Compensation and Liability Act, the Emergency Planning and Community Right to Know Act and the Resource Conservation and Recovery Act. The United States Environmental Protection Agency, or EPA, and/or other authorized federal or state agencies administer and enforce these laws. We are also subject to extensive regulation regarding safety and health matters pursuant to the United States Mine Safety and Health Act of 1977, which is enforced by the U.S. Mine Safety and Health Administration (“MSHA”). Non-compliance with federal, tribal and state laws and regulations could subject us to material administrative, civil or criminal penalties or other liabilities, including suspension or termination of operations. In addition, we may be required to make large and unanticipated capital expenditures to comply with future laws, regulations or orders as well as future interpretations and more rigorous enforcement of existing laws, regulations or orders. Our reclamation obligations under applicable environmental laws will be substantial.

Safety is a core value of WMLP. We use a grass roots approach, encouraging and promoting employee involvement in safety and accepting input from all employees; we feel employee involvement is a pillar of our safety excellence.

Following passage of The Mine Improvement and New Emergency Response Act of 2006, amending the Federal Mine Safety and Health Act of 1977, MSHA significantly increased the oversight, inspection and enforcement of safety and health standards and imposed safety and health standards on all aspects of mining operations. There has also been a dramatic increase in the dollar penalties assessed by MSHA for citations issued over the past two years. The states in which we operate have inspection programs for mine safety and health. Collectively, federal and state safety and health regulations in the coal mining industry are perhaps the most comprehensive and pervasive systems for protection of employee health and safety affecting any segment of U.S. industry.

The following provides brief summaries of certain Federal laws and regulations to which we are subject and their effects upon us:

Surface Mining Control and Reclamation Act

SMCRA establishes minimum national operational, reclamation and closure standards for all surface coal mines. SMCRA requires that comprehensive environmental protection and reclamation standards be met during the course of and following completion of coal mining activities. Permits for all coal mining operations must be obtained from the Federal Office of Surface Mining Reclamation and Enforcement, or OSM, or, where state regulatory agencies have adopted federally approved state programs under SMCRA, the appropriate state regulatory authority. States that operate federally approved state programs may impose standards that are more stringent than the requirements of SMCRA and OSM’s regulations and, in many instances, have done so. Permitting under SMCRA has generally become more difficult in recent years, which adversely affects the availability of coal reserves at our coal mines.

It is our policy to comply in all material respects with the requirements of SMCRA and the state and tribal laws and regulations governing mine reclamation.

Bonding Requirements

Federal and state laws require mine operators to assure, usually through the use of surety bonds, payment of certain long-term obligations, including the costs of mine closure and the costs of reclaiming the mined land. Surety providers are requiring smaller percentages of collateral to secure a bond, which will require us to provide less cash to collateralize bonds to allow us to continue mining. These changes in the terms of the bonds have been accompanied, at times, by an increase in the number of companies willing to issue surety bonds. As of December 31, 2014 , we have posted an aggregate of $34.6 million in surety bonds for reclamation purposes, secured by approximately $9.1 million of cash collateral.

Clean Air Act and Related Regulation

The federal Clean Air Act (“CAA”) and comparable state laws that regulate air emissions affect coal mining operations both directly and indirectly. Direct impacts on coal mining and processing operations include CAA permitting requirements and emission control requirements relating to air pollutants, including particulate matter, which may include controlling fugitive dust. The CAA indirectly affects coal mining operations by extensively regulating the emissions of particulate matter, sulfur dioxide, nitrogen oxides, mercury and other compounds emitted by coal fired power plants. In recent years, Congress has considered legislation that would require increased reductions in emissions of sulfur dioxide, nitrogen oxide and mercury, as well as GHGs. The air emissions programs, regulatory initiatives and standards that may affect our operations, directly or indirectly, include, but are not limited to, the following:

required all new fossil-fuel-fired EGUs to emit no more than 1,000 pounds of CO2 / megawatt hour on an average annual basis, which is based on the CO2 emissions from natural gas combined cycle facilities. The EPA later indicated its intention to issue a new proposal in light of over two million comments on the April 2012 proposal and ongoing developments in the industry. In June 2013, President Obama directed the EPA to issue that new proposal by September 30, 2013, and to finalize it in a timely manner. In September 2013, the EPA revoked its April 2012 proposal and instead proposed new limits, which would require all new coal-fired EGUs to emit no more than 1,100 pounds of CO2 / megawatt hour on an average annual basis, and new natural gas-fired plants to meet a standard of either 1,000 or 1,100 pounds of CO2 / megawatt hour (depending on size). Under the CAA, new source performance standards like the GHG NSPS have binding effect from the date of the proposal. Once NSPSs are finalized, the EPA must issue guidance to states for the issuance of existing source standards. The GHG NSPS as currently proposed may be a major obstacle to the construction and development of any new coal-fired generation capacity because it is unlikely, with a few possible exceptions, that the limits in the proposal can be achieved by a new coal-fired EGU without the use of carbon capture and sequestration technology. EPA has stated that it will finalize the NSPS in the summer of 2015. The finalization of the NSPS is a predicate for issuance of existing source performance standards under Section 111(d) of the CAA. In June of 2014, EPA proposed existing source standards for fossil-fuel fired power plants, which EPA refers to as the Clean Power Plan. EPA’s proposal mandates GHG emission “goals” for each state, beginning in 2020 with reductions through 2030, based on EPA’s assessment of the “best system of emission reduction,” including (1) average heat rate improvements of 6% for coal-fired power plants; (2) the re-dispatch of power based on an assumption that underutilized capacity at natural gas combined cycle facilities can be increased to 70%; (3) the substitution of coal generation with renewable energy; and (4) cumulative annual energy savings rates of 1.5% based on demand-side energy efficiency programs. EPA plans to finalize the rule in the summer of 2015. Once finalized, the states have one year to submit plans to EPA to implement and enforce the state-specific BSER. EPA has stated that if finalized, the Plan would reduce GHG emissions from the power sector by 30 percent from 2005 levels, due primarily to reduced generation at coal-fired power plants.

result in disproportionate impacts on the western U.S. EPA is obligated by court order to finalize the standards by October of 2015.

Climate Change Legislation and Regulations

Numerous proposals for federal and state legislation have been made relating to greenhouse gas, or GHG, emissions (including carbon dioxide) and such legislation could result in the creation of substantial additional costs in the form of taxes or required acquisition or trading of emission allowances. Many of the federal and state climate change legislative proposals use a “cap and trade” policy structure, in which GHG emissions from a broad cross section of the economy would be subject to an overall cap. Under the proposals, the cap would become more stringent with the passage of time. The proposals establish mechanisms for GHG sources such as power plants to obtain “allowances” or permits to emit GHGs during the course of a year. The sources may use the allowances to cover their own emissions or sell them to other sources that do not hold enough emissions allowances for their own operations. Some states, including California, and a number of states in the northeastern and mid-Atlantic regions of the U.S. that are participants in a program known as the Regional Greenhouse Gas Initiative (often referred to as “RGGI”), which is limited to fossil-fuel-burning power plants, have enacted and are currently operating programs that, in varying ways and degrees, regulate GHGs.

In addition, the EPA has issued a notice of finding and determination that emissions of carbon dioxide, methane and other GHGs present an endangerment to human health and the environment, which allows the EPA to begin regulating emissions of GHGs under existing provisions of the CAA. The EPA has begun to implement GHG-related reporting and permitting rules as described above. In June of 2014, the U.S. Supreme Court overturned the EPA’s GHG permitting rules to the extent they required permits based solely on emissions of GHG. Large sources of air pollutants could still be required to install GHG emission reduction technology. Underground coal mines remain subject to the EPA’s GHG Reporting Program,

which required mines to submit annual GHG emission estimates to the EPA, but that program has not been extended to surface coal mines.

The impact of GHG-related legislation and regulations, including a “cap and trade” structure, on us will depend on a number of factors, including whether GHG sources in multiple sectors of the economy are regulated, the overall GHG emissions cap level, the degree to which GHG offsets are allowed, the allocation of emission allowances to specific sources and the indirect impact of carbon regulation on coal prices. We may not recover all of the costs related to compliance with regulatory requirements imposed on us from our customers due to limitations in our agreements. 

Passage of additional state or federal laws or regulations regarding GHG emissions or other actions to limit carbon dioxide emissions could result in fuel switching from coal to other fuel sources by electricity generators and thereby reduce demand for our coal or indirectly the prices we receive in general. In addition, political and regulatory uncertainty over future emissions controls have been cited as major factors in decisions by power companies to postpone new coal-fired power plants. If these or similar measures, such as controls on methane emissions from coal mines, are ultimately imposed by federal or state governments or pursuant to international treaties, our operating costs or our revenues may be materially and adversely affected. In addition, alternative sources of power, including wind, solar, nuclear and natural gas, could become more attractive than coal in order to reduce carbon emissions, which could result in a reduction in the demand for coal and, therefore, our revenues. Similarly, some of our customers, in particular smaller, older power plants, could be at risk of significant reduction in coal burn or closure as a result of imposed carbon costs. The imposition of a carbon tax or similar regulation could, in certain situations, lead to the shutdown of coal-fired power plants, which would materially and adversely affect our coal and power plant revenues.

Clean Water Act

The Clean Water Act, or CWA, and corresponding state and local laws and regulations affect coal mining and power generation operations by restricting the discharge of pollutants, including dredged or fill materials, into waters of the U.S. The CWA provisions and associated state and federal regulations are complex and subject to amendments, legal challenges and changes in implementation. On April 21, 2014, the EPA and the U.S. Army Corps of Engineers jointly release a proposed rule to clarify which waters and wetlands are subject to regulation under the CWA. Recent court decisions, regulatory actions and proposed legislation have created uncertainty over CWA jurisdiction and permitting requirements that could either increase or decrease the cost and time spent on CWA compliance.

Black Lung Benefits Acts

Under the Black Lung Benefits Revenue Act of 1977 and the Black Lung Benefits Reform Act of 1977, as amended in 1981 (collectively “BLBA”), each coal mine operator must secure payment of federal black lung benefits to claimants who are current and former employees to a trust fund for the payment of benefits and medical expenses to eligible claimants. The trust fund is funded by an excise tax on production of up to $0.55 per ton for surface-mined coal, not to exceed 4.4% of the gross sales price. In 2014 , we recognized $2.9 million of expense related to this excise tax.

Comprehensive Environmental Response, Compensation and Liability Act

Under the Comprehensive Environmental Response, Compensation, and Liability Act, also known as CERCLA or Superfund, and similar state laws, responsibility for the entire cost of cleanup of a contaminated site, as well as natural resource damages, can be imposed upon current or former site owners or operators, or upon any party who released one or more designated “hazardous substances” at the site, regardless of the lawfulness of the original activities that led to the contamination. CERCLA also authorizes the EPA and, in some cases, third parties to take actions in response to threats to public health or the environment and to seek to recover from the potentially responsible parties the costs of such action. In the course of our operations, we may have generated and may generate wastes that fall within CERCLA’s definition of hazardous substances. 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 

We may also be an owner or operator of facilities at which hazardous substances have been released by previous owners or operators. We may be responsible under CERCLA for all or part of the costs of clean up facilities at which such substances have been released and for natural resource damages. We have not, to our knowledge, been identified as a potentially responsible party under CERCLA, nor are we aware of any prior owners or operators of our properties that have

been so identified with respect to their ownership or operation of those properties. We also must comply with reporting requirements under the Emergency Planning and Community to Know Act and the Toxic Substances Control Act. We may generate wastes, including “solid” wastes and “hazardous” wastes, that are subject to the federal Resource Conservation and Recovery Act, or RCRA, and comparable state statutes, although certain mining and mineral beneficiation wastes and certain wastes derived from the combustion of coal currently are exempt from regulation as hazardous wastes under RCRA. The EPA has limited the disposal options for certain wastes that are designated as hazardous wastes under RCRA. Furthermore, it is possible that certain wastes generated by our operations that currently are exempt from regulation as hazardous wastes may in the future be designated as hazardous wastes, and therefore be subject to more rigorous and costly management, disposal and clean-up requirements.

The EPA determined that coal combustion residuals (“CCR”) do not warrant regulation as hazardous wastes under RCRA in May 2000. Most state hazardous waste laws do not regulate CCR as hazardous wastes. The EPA also concluded that beneficial uses of CCR, other than for mine filling, pose no significant risk and no additional national regulations of such beneficial uses are needed. However, the EPA determined that national non-hazardous waste regulations under RCRA are warranted for certain wastes generated from coal combustion, such as coal ash, when the wastes are disposed of in surface impoundments or landfills or used as minefill. EPA Administrator Gina McCarthy signed the final rule relating to the disposal of CCR from electric utilities on December 19, 2014 and submitted it to the Federal Register for publication. The final rule regulates CCR as solid waste under RCRA. The final rule establishes national minimum criteria for existing and new CCR landfills, surface improvements and lateral expansions. The criteria include location restrictions, design and operating criteria, groundwater monitoring and corrective action, closure requirements and post-closure care and recordkeeping, notification and interest posting requirements. The rule is largely silent on the reuse of coal ash, but the EPA has plans to develop in 2015 a conceptual model for beneficial uses of coal ash. These changes in the management of CCR could increase our and our customers’ operating costs and potentially reduce their ability to purchase coal. In addition, contamination caused by the past disposal of CCR, including coal ash, could lead to citizen suit enforcement against our customers under RCRA or other federal or state laws and potentially reduce the demand for coal.

Endangered Species Act

The federal Endangered Species Act, or ESA, and similar state laws protect species threatened with extinction. Protection of endangered and threatened species may cause us to modify mining plans or develop and implement species-specific protection and enhancement plans to avoid or minimize impacts to endangered species or their habitats. A number of species indigenous to the areas where we operate are protected under the ESA. Based on the species that have been identified and the current application of applicable laws and regulations, we do not believe that there are any species protected under the ESA or state laws that would materially and adversely affect our ability to mine coal from our properties.

Employees

We are managed and operated by the directors and officers of our general partner. Additionally, full-time employees are employed by WCC, the owner of our general partner, and its affiliates who provide executive, general and administrative services to us. For further information, please read “Directors, Executive Officers and Corporate Governance” and “Certain Relationships and Related Transactions, and Director Independence.”

As of December 31, 2014 , through our GP, we employed 602 full-time employees to conduct our operations, including 470 employees involved in active mining operations, 107 employees in other operations, and 25 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.

As part our ongoing restructuring, 81 full-time employees have been moved and are employed by WCC in support of us and 50 full-time positions have been eliminated resulting in 471 full-time employees employed by us, through our GP, at March 3, 2015 .

Additional Information

We file annual, quarterly and current reports, proxy statements and other information with the Securities and Exchange Commission (the “SEC”). You may access and read our filings without charge through the SEC’s website, at 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 1-800-SEC-0330 for further information regarding the operation of its public reference room.

We also make our public reports available through our website, www.oxfordresources.com, as soon as practicable after we file or furnish them with the SEC. You may also request copies of the documents, at no cost, by telephone at (855) 922-6463 or by mail at Westmoreland Resource Partners, LP, 9540 South Maroon Circle, Suite 200, Englewood, CO 80112. The information on our website is not part of this Annual Report on Form 10-K.

GLOSSARY OF SELECTED TERMS 

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

Probable coal reserves : Coal reserves for which quantity and grade and/or quality are computed from information similar to that used for proven coal reserves, but the sites for inspection, sampling and measurement are farther apart or are otherwise less adequately spaced. The degree of assurance, although lower than that for proven coal reserves, is high enough to assume continuity between points of observation.

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

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

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

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

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

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

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

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

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

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

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

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

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