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EX-23.1 - EXHIBIT 23.1 - Westmoreland Resource Partners, LPex231.htm

UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549 
Form 10-K
ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
For the fiscal year ended December 31, 2014
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
_________________________
Westmoreland Resource Partners, LP
(Exact name of registrant as specified in its charter)
____________________________________________________
Delaware
77-0695453
(State or other jurisdiction of
incorporation or organization)
(I.R.S. Employer
Identification Number)
9540 South Maroon Circle, Suite 200, Englewood, CO 801112
(Address of principal executive offices and zip code) 
(855) 922-6463
(Registrant’s telephone number, including area code)
Securities registered pursuant to Section 12(b) of the Act: Common Units representing limited partner interests 
Title of Each Class
 
Name of Each Exchange On Which Registered
Common Units Representing Limited Partner Interests
 
New York Stock Exchange
 
Securities registered pursuant to Section 12(g) of the Act: None
____________________________________________________ 
Indicate by check mark if the registrant is a well-known seasoned issuer, as defined in Rule 405 of the Securities Act.    ☐  Yes    ☒  No
Indicate by check mark if the registrant is not required to file reports pursuant to Section 13 or Section 15(d) of the Act.    ☐  Yes    ☒    No
Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days.    ☒  Yes    ☐  No
 Indicate by check mark whether the registrant has submitted electronically and posted on its corporate Web site, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T (§ 232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files).    ☒  Yes    ☐  No
Indicate by check mark if disclosure of delinquent filers pursuant to Item 405 of Regulation S-K is not contained herein, and will not be contained, to the best of registrant’s knowledge, in definitive proxy or information statements incorporated by reference in Part III of this Form 10-K or any amendment to this Form 10-K.    ☐
Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, or a smaller reporting company. See the definitions of “large accelerated filer,” “accelerated filer,” and “smaller reporting company” in Rule 12b-2 of the Exchange Act. (Check one)
Large Accelerated Filer
Accelerated Filer
Non-Accelerated Filer
Smaller Reporting Company
Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act).    ☐  Yes    ☒  No
The aggregate market value of the common units held by non-affiliates of the registrant (treating all executive officers and directors of the registrant, for this purpose, as if they may be affiliates of the registrant) was $8,112,648 as of June 30, 2014, based on the reported closing price of the common units as reported on the New York Stock Exchange on June 30 2014.
As of March 3, 2015, 5,711,636 common units were outstanding. The common units trade on the New York Stock Exchange under the ticker symbol “WMLP.” 

DOCUMENTS INCORPORATED BY REFERENCE: None


 

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TABLE OF CONTENTS 
 
 
Page
Cautionary Statement About Forward-Looking Statements  
 
 
 
 
PART I
 
 
 
 
Item 1.
Business
 
 
 
 
Glossary of Selected Terms
 
 
 
Item 1A.
Risk Factors
 
 
 
Item 1B.
Unresolved Staff Comments
 
 
 
Item 2.
Properties
 
 
 
Item 3.
Legal Proceedings
 
 
 
Item 4.
Mine Safety Disclosures
 
 
 
 
PART II
 
 
 
 
Item 5.
Market for Registrant’s Common Equity, Related Unitholder Matters and Issuer Purchases of Equity Securities
 
 
 
Item 6.
Selected Financial and Operating Data
 
 
 
Item 7.
Management’s Discussion and Analysis of Financial Condition and Results of Operations
 
 
 
Item 7A.
Quantitative and Qualitative Disclosures About Market Risk
 
 
 
Item 8.
Financial Statements and Supplementary Data
 
 
 
Item 9.
Changes in and Disagreements With Accountant on Accounting and Financial Disclosure
 
 
 
Item 9A.
Controls and Procedures
 
 
 
Item 9B.
Other Information
 
 
 
 
PART III
 
 
 
 
Item 10.
Directors, Executive Officers and Corporate Governance
 
 
 
Item 11.
Executive Compensation
 
 
 
Item 12.
Security Ownership of Certain Beneficial Owners and Management and Related Unitholder Matters
 
 
 
Item 13.
Certain Relationships and Related Transactions, and Director Independence
 
 
 
Item 14.
Principal Accountant Fees and Services
 
 
 
 
PART IV
 
 
 
 
Item 15.
Exhibits and Financial Statement Schedules


 

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Cautionary Statement About Forward-Looking Statements
This Annual Report on Form 10-K contains “forward-looking statements.” Forward-looking statements can be identified by words such as “anticipates,” “intends,” “plans,” “seeks,” “believes,” “estimates,” “expects,” “may,” “plan,” “predict,” “project,” “should,” “could,” “will” and similar references to future periods. Examples of forward-looking statements include, but are not limited to, statements we make throughout this report regarding recent significant transactions and their anticipated effects on us, and statements in “Item 7 - Management’s Discussion and Analysis of Financial Condition and Results of Operations” regarding factors that may cause our results of operation in future periods to differ from our expectations.
Forward-looking statements are based on our current expectations and assumptions regarding our business, the economy and other future conditions. Because forward-looking statements relate to the future, they are subject to inherent uncertainties, risks and changes in circumstances that are difficult to predict. Our actual results may differ materially from those contemplated by the forward-looking statements. We therefore caution you against relying on any of these forward-looking statements. They are statements neither of historical fact nor guarantees or assurances of future performance. Important factors that could cause actual results to differ materially from those in the forward-looking statements include political, economic, business, competitive, market, weather and regulatory conditions and the following:
Our substantial level of indebtedness and our ability to adhere to financial covenants related to our borrowing arrangements;
Inaccuracies in our estimates of our coal reserves;
The effect of consummating financing, acquisition and/or disposition transactions;
Our potential inability to expand or continue current coal operations due to limitations in obtaining bonding capacity for new mining permits, and/or increases in our mining costs as a result of increased bonding expenses;
The effect of prolonged maintenance or unplanned outages at our operations or those of our major power generating customers;
The inability to control costs;
Competition within our industry and with producers of competing energy sources;
Our relationships with, and other conditions affecting, our customers;
The availability and costs of key supplies or commodities, such as diesel fuel, steel, explosives and tires;
Potential title defects or loss of leasehold interests in our properties, which could result in unanticipated costs or an inability to mine the properties;
The effect of legal and administrative proceedings, settlements, investigations and claims, including any related to citations and orders issued by regulatory authorities, and the availability of related insurance coverage;
Existing and future legislation and regulation affecting both our coal mining operations and our customers’ coal usage, governmental policies and taxes, including those aimed at reducing emissions of elements such as mercury, sulfur dioxides, nitrogen oxides, particulate matter or greenhouse gases;
The effect of Environmental Protection Agency’s inquiries and regulations on the operations of the power plants to which we provide coal;
Our ability to pay our quarterly distributions which substantially depends upon our future operating performance (which may be affected by prevailing economic conditions in the coal industry), debt covenants, and financial, business and other factors, some of which are beyond our control;
Adequacy and sufficiency of our internal controls;
Our potential need to recognize additional impairment and/or restructuring expenses associated with our operations, as well as any changes to previously identified impairment or restructuring expense estimates, including additional impairment and restructuring expenses associated with our Illinois Basin operations; and
Other factors that are described in “Risk Factors” in this report and under the heading “Risk Factors” found in our other reports filed with the Securities and Exchange Commission (“SEC”), including our Annual Reports on Form 10-K and our Quarterly Reports on Form 10-Q.
Unless otherwise specified, the forward-looking statements in this report speak as of the filing date of this report. Factors or events that could cause our actual results to differ may emerge from time-to-time, and it is not possible for us to predict all of them. We undertake no obligation to publicly update any forward-looking statements, whether because of new information, future developments or otherwise, except as may be required by law.

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Reserve engineering is a process of estimating underground accumulations of coal that cannot be measured in an exact way. The accuracy of any reserve estimate depends on the quality of available data, the interpretation of such data and price and cost assumptions made by our reserve engineers. In addition, the results of mining, testing and production activities may justify revision of estimates that were made previously. If significant, such revisions would change the schedule of any further production and development of reserves. Accordingly, reserve estimates may differ from the quantities of coal that are ultimately recovered.

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PART I
 
Introduction
This report is both our 2014 Annual Report to unitholders and our 2014 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 "WMLP," "the Partnership," "we," "our," "us" and similar terms refer to Westmoreland Resource Partners, LP, the parent entity, and its consolidated subsidiaries. Also, "our GP" means Westmoreland Resources GP, LLC, the general partner of WMLP.
The term "coal reserves" as used in this Annual 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 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.
 

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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."

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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:
Effect a 12-to-1 reverse split of our common and general partner units;
Convert all of our outstanding subordinated units to liquidation units (with no distribution or voting rights, other than in connection with a liquidation);
Waive and eliminate our current cumulative common unit arrearages and also eliminate the concept of common unit arrearages going forward;
Reset the minimum quarterly distribution to $0.1333 per common unit;
Restructure the incentive distribution rights (the “IDRs”) held by our GP to provide that the IDRs will be entitled to receive (i) 13% of quarterly distributions over $0.1533 per unit and up to $0.1667 per unit; (ii) 23% of quarterly distributions over $0.1667 per unit and up to $0.2000 per unit; and (iii) 48% of quarterly distributions over $0.2000 per unit; and
Suspend the distributions on the IDRs for six quarters, provided that such suspension may be reduced to three quarters if, during the suspension period, additional dropdown transactions aggregating greater than $35.0 million in enterprise value are undertaken by our GP or affiliates of our GP that are reasonably expected to provide accretion to per unit common unitholder distributions.
Special Distribution to Public 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

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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:
 
 
 
 
As of December 31, 2014
Mining Complex
 
Production for the Year Ended December 31, 2014
 
Total Proven & Probable Reserves
 
Proven Reserves
 
Probable Reserves
 
Average Heat Value (BTU/lb)
 
Average Sulfur Content (%)
 
Primary Transportation Methods
 
 
(tons in thousands)
 
 
 
 
 
 
Surface Mining Operations:
 
 
 
 
 
 
 
 
 
 
 
 
Northern Appalachia (principally Ohio):
 
 
 
 
 
 
 
 
 
 
Cadiz
 
3,074

 
7,891

 
7,148

 
743

 
11,350

 
2.7
%
 
Barge, Rail, Truck
Tuscarawas County
 
1,185

 
5,966

 
5,966

 

 
11,775

 
4.1
%
 
Truck
Plainfield
 

 
3,447

 
3,447

 

 
11,703

 
4.4
%
 
Truck
Belmont County
 
403

 
10,741

 
10,122

 
619

 
11,804

 
4.3
%
 
Barge, Truck
New Lexington
 
685

 
6,117

 
5,596

 
521

 
11,177

 
4.1
%
 
Rail, Truck
Noble County
 
251

 
1,327

 
1,311

 
16

 
11,239

 
4.8
%
 
Barge, Truck
Illinois Basin (Kentucky):
 
 
 
 
 
 
 
 
 
 
 
 
Muhlenberg County
 

 
16,296

 
15,165

 
1,131

 
11,314

 
3.6
%
 
 
Total Surface Mining Operations
 
5,598

 
51,785

 
48,755

 
3,030

 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Coal Reserves Leased to Others:
 
 
 
 
 
 
 
 
 
 
 
 
Kemmerer(1)
 
 
 
30,354

 
30,354

 

 
9,818

 
0.64
%
 
 
Tusky
 
 
 
24,331

 
18,965

 
5,366

 
12,900

 
2.1
%
 
 
Total Coal Reserves Leased to Others
 
54,685

 
49,319

 
5,366

 
 
 
 
 
 
Total
 
 
 
106,470

 
98,074

 
8,396

 
 
 
 
 
 
(1)  
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. 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.

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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, 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

(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.

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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

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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.

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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, 2014.
In December 2013, we idled our surface mining complex in the Illinois Basin, located in western Kentucky. The following table provides summary information regarding our mining complex in the Illinois Basin 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)
Muhlenberg
 
Island River
 

 
Barge, Truck
 

 

 
0.3

 
2.2

(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

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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:
our Barb Tipple blending and coal crushing facility, adjacent to a customer’s power plant near Coshocton, Ohio;
our Strasburg preparation plant near Strasburg, Ohio;
our Conesville preparation plant in Coshocton County, Ohio, also adjacent to a customer’s power plant near Coshocton, Ohio;
our Bellaire river terminal on the Ohio River in Bellaire, Ohio.
Royalty Revenues
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.

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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:
the receipt of a settlement payment of $19.5 million to compensate us for lost profits on coal sales to a customer due to a wrongfully terminated coal supply agreement;
service fees of $0.6 million we earned for operating a transloader for a third party that offloads coal from railcars on the Ohio Central Railroad at one of our customer's power plants;
providing contract labor and selling small amounts of clay to Tunnell Hill Reclamation, LLC, a landfill operator and subsidiary of Tunnel Hill Partners, LP, an entity owned by AIM and C&T, our former sponsors, totaling $1.1 million; and
service fees we earned for hauling and disposing of ash at a third party landfill for two municipal utilities totaling $0.2 million.
For more information regarding our relationships and our 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.

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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.

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During 2014, we continued to maintain reportable and lost time incident rates significantly below Appalachian basin averages, as indicated in the table below.
 
2014
 
Reportable Rate
 
Lost Time Rate
WMLP Mines
1.14

 
0.50

Appalachian Basin Mines
2.15

 
1.56

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:
Greenhouse Gas Emissions Standards. In April 2012, the EPA proposed new limits on GHG emissions from new electric generating units (“EGUs”) under Section 111 of the CAA (“GHG NSPS”). The proposed limits are referred to as “new source performance standards” because they apply only to new or reconstructed sources. The proposal

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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.
Mercury Air Standards. In February 2012, the EPA published national emission standards under Section 112 of the CAA setting limits on hazardous air pollutant emissions from coal- and oil-fired EGUs. The “Mercury Air Toxics Standards,” or “MATS Rule,” is expected to be one of the most costly rules ever issued by the EPA. It has also proven highly controversial, drawing numerous legal challenges in the U.S. Court of Appeals for the D.C. Circuit as well as petitions for administrative reconsideration filed with the EPA. While the MATS Rule will generally require all coal- and oil-fired EGUs to reduce their hazardous air pollutant emissions, it is particularly problematic for any new coal-fired sources. This is because the new-source limits are so low that they cannot be accurately measured and vendors of pollution control equipment have said they cannot provide commercial guarantees that the limits can be achieved. And because such guarantees are a precondition to obtaining financing in the marketplace, the MATS Rule effectively amounts to a ban on the construction of new coal-fired EGUs. In July 2012, however, the EPA agreed to reconsider the new source standards in response to requests by industry. In November 2012, the EPA published proposed new source standards with revised, less stringent, emission limits. In April 2013, the EPA published new source limits under the MATS Rule, and then in June 2013, the EPA reopened for 60 days the public comment period on certain startup and shutdown provisions included in the November 2012 proposal. In June 2013, certain environmental organizations and industry groups filed appeals of the rule as revised. The D.C. Circuit upheld the standards, but the Supreme Court accepted certiorari and will hear an industry challenge in 2015.
National Ambient Air Quality Standards (“NAAQS”) for Criteria Pollutants. The CAA requires the EPA to set standards, referred to as NAAQS, for six common air pollutants, including nitrogen oxide and sulfur dioxide. Areas that are not in compliance (referred to as non-attainment areas) with these standards must take steps to reduce emissions levels. Meeting these limits may require reductions of nitrogen oxide and sulfur dioxide emissions. Although our operations are not currently located in non-attainment areas, we could be required to incur significant costs to install additional emissions control equipment, or otherwise change our operations and future development if that were to change. On June 22, 2010, the EPA published a final rule that tightens the NAAQS for sulfur dioxide. On February 17, 2012, the EPA published final NAAQS for nitrogen dioxide. On January 15, 2013, the EPA published final NAAQS for particulate matter; the EPA lowered the annual standard for particles less than 2.5 micrometers in diameter but maintained the NAAQS for particles less than 10 micrometers in diameter. EPA finalized designations for the sulfur dioxide NAAQS in 2013 for a handful of counties and delayed designations for the remainder of the country. EPA has proposed guidance that would allow states to use both monitoring and modeling for the remaining designations, but has not finalized the guidance or set any deadlines for state recommendations. EPA finalized nonattainment designations for nitrogen dioxide in January 2012. We do not know whether or to what extent these developments might affect our operations or our customers’ businesses. In 2008, the EPA finalized the current 8-hour ozone standard. The EPA agreed to reconsider the standard, and in 2010 the EPA proposed to further reduce the standard. Under orders from President Obama, this NAAQS was not finalized. In December 2014, EPA proposed to lower the primary ozone standard to between 65 ppb and 70 ppb from the current standard of 75 ppb, which would

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result in disproportionate impacts on the western U.S. EPA is obligated by court order to finalize the standards by October of 2015.
Clean Air Interstate Rule and Cross-State Air Pollution Rule. (“CAIR”) and Cross-State Air Pollution Rule (“CSAPR”). The CAIR calls for power plants in 28 states and the District of Columbia to reduce emission levels of sulfur dioxide and nitrogen oxide pursuant to a cap-and-trade program similar to the system now in effect for acid rain. In 2008, the U.S. Court of Appeals for the District of Columbia Circuit found that the CAIR was fatally flawed, but ultimately agreed to allow it to remain in place pending the EPA’s development of a replacement rule because of concerns about potential disruptions. In June 2011, the EPA finalized the CSAPR as a replacement rule to the CAIR, which requires 28 states in the Midwest and eastern seaboard of the United States to reduce power plant emissions that cross state lines and contribute to ozone and/or fine particle pollution in other states. Under the CSAPR, the first phase of the nitrogen oxide and sulfur dioxide emissions reductions would commence in 2012 with further reduction effective in 2014. On December 15, 2011, the EPA finalized a supplemental rule making to require Iowa, Michigan, Missouri, Oklahoma and Wisconsin to make summertime reductions to nitrogen oxide emissions under the CSAPR ozone-season control program. However, on December 30, 2011, the U.S. Court of Appeals for the District of Columbia Circuit stayed the implementation of CSAPR pending resolution of judicial challenges to the rules and ordered the EPA to continue enforcing the CAIR until the pending legal challenges have been resolved. In August 2012, the U.S. Court of Appeals vacated the CSAPR in a 2-to-1 decision and left the CAIR standards in place. In January 2013, the court rejected the EPA’s request for en banc review. In March 2013, the Solicitor General’s office, on behalf of the EPA, and separately certain non-governmental organizations, filed petitions for writs of certiorari with the U.S. Supreme Court seeking review of the U.S. Court of Appeals decision, and the U.S. Supreme Court granted those petitions in June 2013. The Supreme Court reversed the D.C. Circuit and upheld the rule, but remanded the case to the D.C. Circuit for further proceedings, which are ongoing. EPA issued an interim final rule in December 2014 that would require the first phase of reductions in 2015 and 2016, with the second phase of reductions beginning in 2017.
Other Programs. A number of other air-related programs may affect the demand for coal and, in some instances, coal mining directly. For example, the EPA has initiated a regional haze program designed to protect and improve visibility at and around national parks, national wilderness areas and international parks. The EPA’s new source review program under certain circumstances requires existing coal-fired power plants, when modifications to those plants significantly change emissions, to install the more stringent air emissions control equipment required of new plants, and concerns about potential failures to comply have resulted in a number of high-profile enforcement actions and settlements over the years resulting in some instances in settlements under which operators install expensive new emissions control equipment. The Acid Rain program under Title IV of the CAA continues to impose limits on overall sulphur dioxide and nitrogen oxide emissions from regulated EGUs. In June 2013, President Obama issued a Climate Action Plan, which included a focus on methane reductions from coal mines. In January 2015, the Administration issued its methane strategy, but it did not include requirements for coal mines. Indeed, in 2014 the D.C. Circuit upheld EPA’s decision not 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 coal mines.
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,

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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

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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.

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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.

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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.

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Probable coal reserves: Coal reserves for which quantity and grade and/or quality are computed from information similar to that used for proven coal reserves, but the sites for inspection, sampling and measurement are farther apart or are otherwise less adequately spaced. The degree of assurance, although lower than that for proven coal reserves, is high enough to assume continuity between points of observation.
Proven coal reserves: Coal reserves for which (i) quantity is computed from dimensions revealed in outcrops, trenches, workings or drill holes; (ii) grade and/or quality are computed from the results of detailed sampling; and (iii) the sites for inspection, sampling and measurement are spaced so closely and the geologic character is so well defined that size, shape, depth and mineral content of coal reserves are well-established.
Proven and probable coal reserves: Coal reserves which are a combination of proven coal reserves and probable coal reserves.
Reclamation: The restoration of mined land to original contour, use or condition.
Recoverable reserve: The amount of coal that can be extracted from the Reserves. The recovery factor for surface mines is typically between 80% and 90%.
Reserve: That part of a mineral deposit that could be economically and legally extracted.
Selective catalytic reduction, or SCR, device: A means of converting nitrogen oxides, also referred to as NOx, with the aid of a catalyst into diatomic nitrogen (N2) and water (H2O).
Strip ratio: Strip ratio refers to the number of bank cubic yards of overburden or waste that must be removed to extract one ton of coal.
Sub-bituminous Coal: Dull coal that ranks between lignite and bituminous coal. Its moisture content is between 20% and 30% by weight and its heat content ranges from 7,800 to 9,500 Btus per pound.
Sulfur: One of the elements present in varying quantities in coal and which contributes to environmental degradation when coal is burned. Sulfur dioxide is produced as a gaseous byproduct of coal combustion.
Tipple: A structure where coal is loaded in railroad cars or trucks.
Thermal coal (aka Steam coal): Coal burned by electric power plants and industrial steam boilers to produce electricity, steam or both.
Tons: A “short,” or net, ton is equal to 2,000 pounds. A “long,” or British, ton is equal to 2,240 pounds. A “metric” ton is approximately 2,205 pounds. The short ton is the unit of measure referred to in this report.
Total maximum daily load: A calculation of the maximum amount of a pollutant that a body of water can receive per day and still safely meet water quality standards.

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Item 1A.Risk Factors
Risks Related to Our Business
Our 2014 Financing Agreement contains operating and financial restrictions that restrict our distributions, business and financing activities.
Our 2014 Financing Agreement contains significant restrictions on our ability to incur additional liens or indebtedness, make fundamental changes or dispositions, make changes in the nature of our business, make certain investments, loans or advances, create certain lease obligations, make capital expenditures in excess of a certain amount, enter into transactions with affiliates, issue equity interests, and modify indebtedness, organizational and certain other documents. The 2014 Financing Agreement also contains covenants requiring us to maintain certain financial ratios and limits our ability to pay distributions to our unitholders, allowing such distributions only under specified circumstances.
The provisions of the 2014 Financing Agreement 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 the 2014 Financing Agreement could result in a default or an event of default that could enable our lenders to declare the outstanding principal of our debt under the 2014 Financing Agreement, together with accrued and unpaid interest, to be immediately due and payable. If the payment of such debt is accelerated, our assets may be insufficient to repay such debt in full, and our unitholders could experience a partial or total loss of their investment.
Our ability to comply with the covenants and restrictions contained in the 2014 Financing Agreement may be affected by events beyond our control that could hinder our ability to meet our financial forecasts, including prevailing economic, financial and industry conditions.  If market or other economic conditions deteriorate, our ability to comply with these covenants may be impaired.  If we violate any of the covenants or restrictions in the 2014 Financing Agreement, our indebtedness under the 2014 Financing Agreement 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 the 2014 Financing Agreement are secured by substantially all of our assets and, if we are unable to repay our indebtedness under the 2014 Financing Agreement, the lenders could seek to foreclose on such assets.
For more information, please read Note 10: Long-Term Debt – Credit Facilities Generally included in the notes to the consolidated financial statements included in “Item 8 - Financial Statements and Supplementary Data.”
Debt levels may limit our flexibility in obtaining additional financing and in pursuing other business opportunities.
 We have a substantial amount of indebtedness. At December 31, 2014, we had a total outstanding indebtedness of $175.0 million under our 2014 Financing Agreement. Our level of indebtedness could have significant consequences to us and our unitholders, including the following:
our ability to obtain additional financing, if necessary, for working capital, capital expenditures (including acquisitions) or other purposes may be impaired or such financing may not be available on favorable terms;
our ability to meet financial covenants may affect our flexibility in planning for and reacting to changes in our business, including possible acquisition opportunities;
our need to use a portion of our cash flow to make principal and interest payments will reduce the amount of funds that would otherwise be available for operations, distributions, and future business opportunities;
our increased vulnerability to competitive pressures or a downturn in our business or the economy generally; and
our flexibility in responding to changing business and economic conditions.
These factors could have a material adverse effect on our business, financial condition, results of operations or prospects. Increases in our total indebtedness would increase our total interest expense costs. Our ability to service our indebtedness will depend upon, among other things, our future financial and operating performance, which will be affected by prevailing economic conditions and financial, business, regulatory and other factors, some of which are beyond our

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control. If our operating results are not sufficient to service our current or future indebtedness, we will be forced to take actions such as reducing or delaying our business activities, acquisitions, investments and/or capital expenditures, selling assets, restructuring or refinancing our indebtedness, or seeking additional equity capital or bankruptcy protection. We may not be able to effect any of these remedies on satisfactory terms, or at all.
Certain provisions in our long-term supply contracts may provide limited protection during adverse economic conditions, may result in economic penalties, and/or may permit customers to terminate such contracts.
Price adjustment, "price re-opener" and other similar provisions in our supply contracts may reduce the protection from short-term coal price volatility traditionally provided by such contracts. Price re-opener provisions typically require the parties to agree on a new price. Failure of the parties to agree on a price under a price re-opener provision can lead to termination of the contract. Any adjustment or renegotiations leading to a significantly lower contract price could adversely affect our business, financial condition and/or results of operations.
Coal supply contracts also typically contain force majeure provisions allowing temporary suspension of performance by our customers or us during the duration of specified events beyond the control of the affected party. Most of our coal supply contracts also contain provisions requiring us to deliver coal meeting quality thresholds for certain characteristics such as Btu, sulfur content, ash content, hardness and ash fusion temperature. Failure to meet these specifications could result in economic penalties, including price adjustments, the rejection of deliveries or termination of the contracts. In addition, certain of our supply contracts permit the customer to terminate the contract in the event of changes in regulations affecting our industry that increase the price of coal beyond a specified limit. Any events leading to the termination or suspension of one or more contracts could adversely affect our business, financial condition and/or results of operations.
For more information, please read “Part I, Item 1 - Business -Long-term coal supply contracts.”
We depend on supply contracts with a few customers for a significant portion of our revenues.
We sell a material portion of our coal under supply contracts. As of December 31, 2014, we had sales commitments for 64.6% of our estimated coal production (including purchased coal to supplement our production) for the year ending December 31, 2015. When our current contracts with customers expire, our customers may decide not to extend existing contracts or enter into new contracts. For the year ended December 31, 2014, we derived 99.1% of our total revenues from coal sales to our ten largest customers (including their affiliates), with our top three customers (including their affiliates) accounting for 87.5% of such revenues.
 In the absence of long-term contracts, our customers may decide to purchase fewer tons of coal than in the past or on different terms, including different pricing terms. Negotiations to extend existing contracts or enter into new long-term contracts with those and other customers may not be successful. In addition, interruption in the purchases by or operations of our principal customers could adversely affect our business, financial condition and/or results of operations. Unscheduled maintenance outages at our customers’ power plants, unseasonably moderate weather, or increases in the production of alternative clean-energy generation such as wind power or decreases in the price of competing fossil fuels such as natural gas are examples of conditions that might cause our customers to reduce their purchases. We may have difficulty identifying alternative purchasers of our coal if our existing customers suspend or terminate their contracts.
Additionally, certain of our long-term contracts are set to expire in the next several years. Should we be unable to successfully renew any or all of these expiring contracts, the reduction in the sale of our coal would adversely affect our operating results and liquidity and could result in significant impairments to our mines should we be unable to execute new long-term coal supply agreements for the affected mines.
For more information, please read “Part I, Item 1 - Business - Customers” and - Long-term coal supply contracts.”
We depend upon our ability to collect payments from our customers.
Our ability to receive payment for the coal we sell depends on the continued creditworthiness of our customers. Periods of economic volatility and tight credit markets increase the risk that we may not be paid.
If the creditworthiness of a customer declines, this would increase the risk that we may not be able to collect payment for some or all of the coal we delivered to that customer. If we determine that a customer is not creditworthy, we may not be required to deliver coal under the customer’s coal sales contract. If we are able to withhold shipments, we may

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decide to sell the customer’s coal on the spot market, which may be at prices lower than the contract price, or we may be unable to sell the coal at all.
Also, competition with other coal suppliers could force us to extend credit to customers on terms that could increase the risk of payment default.
 In addition, we sell some of our coal to brokers who may resell our coal to end users, including utilities. These coal brokers may have only limited assets, making them less creditworthy than the end users. Under some of these arrangements, we have contractual privity only with the brokers and may not be able to pursue claims against the end users.
The bankruptcy or financial deterioration of any of our customers, whether an end user or a broker, could adversely affect our business, financial condition and/or results of operations.
A decline in demand for coal could adversely affect our ability to sell the coal we can produce and a decline in coal prices could render production from our coal reserves uneconomical.
Our results of operations and the value of our coal reserves are significantly dependent upon the prices we receive for our coal, as well as our ability to improve productivity and control costs.  The prices we receive for coal depend upon factors beyond our control, including:
the domestic and foreign supply and demand for coal;
the quantity and quality of coal available from competitors;
a decline in prices under existing contracts where the pricing is tied to and adjusted periodically based on indices reflecting current market pricing;
competition for production of electricity from non-coal sources, including the price and availability of alternative fuels;
domestic air emission standards for coal-fueled power plants and the ability of coal-fueled power plants to meet these standards by installing scrubbers or other means;
adverse weather, climate or other natural conditions, including natural disasters;
the level of domestic and foreign taxes;
domestic and foreign economic conditions, including economic slowdowns;
legislative, regulatory and judicial developments, environmental regulatory changes or changes in energy policy and energy conservation measures that would adversely affect the coal industry, such as legislation limiting carbon emissions or providing for increased funding and incentives for alternative energy sources;
the proximity to, capacity of and cost of transportation and port facilities; and
market price fluctuations for sulfur dioxide emission allowances.
Any adverse change in these factors could result in a decline in demand and lower prices for our coal.  
The risk of prolonged recessionary conditions could adversely affect our financial condition and results of operations.
Because we sell substantially all of our coal to electric utilities, our business and results of operations remain closely linked to demand for electricity. Recent economic uncertainty has raised the risk of prolonged recessionary conditions. Historically, global demand for basic inputs, including electricity production, has decreased during periods of economic downturn. If demand for electricity production decreases, our financial condition and results of operations could be adversely affected. Furthermore, because we typically seek to enter into long-term arrangements for the sale of a substantial portion of our coal, the average sales price we receive for our coal may lag behind any general economic recovery.
Competition in the North American coal industry may adversely affect our revenues and results of operations.
Many of our competitors in the North American coal industry are major coal producers who have significantly greater financial resources than we do. The intense competition among coal producers may impact our ability to retain or attract customers and may therefore adversely affect our revenues and results of operations. Among other things, competitors could develop new mines that compete with our mines, have higher quality coal than our mines or build or obtain access to rail lines that would adversely affect the competitive position of our mines. Additionally, during the last several years, the U.S. coal industry has experienced increased consolidation, which has contributed to the industry becoming more

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competitive.  Increased competition by coal producers or producers of alternate fuels could decrease the demand for, or pricing of, or both, for our coal, adversely affecting our business, financial condition and/or results of operations. For more information, please read “Part I, Item 1 - Business - Competition.”
Any changes in consumption patterns by utilities away from the use of coal, such as changes resulting from low natural gas prices, could affect our ability to sell the coal we produce.
We compete with coal producers in Northern Appalachia and the Illinois Basin and in other coal producing regions of the United States.  The domestic demand for, and prices of, our coal primarily depend on coal consumption patterns of the domestic electric utility industry.  Thermal coal accounted for 100% of our coal sales volume for the year ended December 31, 2014. During this period, 74.3% of our thermal coal sales were to electric utilities for use primarily as fuel for domestic electricity consumption. In addition to competing with other coal producers, we compete generally with producers of other fuels. The amount of coal consumed by the domestic electric utility industry is affected primarily by the overall demand for electricity, environmental and other governmental regulations, and the price and availability of competing fuels for power plants such as nuclear, natural gas and oil, as well as alternative sources of energy. In 2014, the EIA estimates that coal consumption in the electric power sector totaled 863.8 million tons, or 92.9% of total U.S. coal consumption, a historic low, due to low natural gas prices paid by the electric generators that led to a significant increase in the share of natural gas-fired power generation. A further decrease in coal consumption by the electric utility industry could adversely affect the demand for, and price of, coal, which could negatively impact our results of operations and liquidity.
The economic stability of these markets has a significant effect on the demand for coal and the level of competition in supplying these markets.
Some power plants are fueled by natural gas because of the relatively lower construction costs of such plants compared to coal-fired plants and because natural gas is a cleaner burning fuel. In addition, some states have adopted or are considering legislation that encourages domestic electric utilities to switch from coal-fired power generation plants to natural gas powered plants. Further, legislation requiring, subsidizing or providing tax benefits for the use of alternative energy sources and fuels, or legislation providing financing or incentives to encourage continuing technological advances in this area, could further enable alternative energy sources to become more competitive with coal. Passage of these and other state or federal laws or regulations limiting carbon dioxide emissions could result in fuel switching, from coal to other fuel sources, by purchasers of our coal. Such laws and regulations could also mandate decreases in carbon dioxide emissions from coal-fired power plants, impose taxes on carbon emissions or require certain technology to capture and sequester carbon dioxide from coal-fired power plants. If these or similar measures are ultimately imposed by federal or state governments or pursuant to international treaty, our reserves and operating costs may be materially and adversely affected. Similarly, alternative fuels (non-fossil fuels) 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.
Recently, the supply of natural gas has reached record highs and the price of natural gas has remained at depressed levels for sustained periods due to extraction techniques involving horizontal drilling and hydraulic fracturing that have led to economic access to large quantities of natural gas in the United States, making it an attractive competing fuel. A continuing decline in the price of natural gas, or continuing periods of sustained low natural gas prices, could cause demand for coal to decrease, result in fuel switching and decreased coal consumption by electricity-generating utilities and adversely affect the price of our coal. Sustained low natural gas prices may cause utilities to phase-out or close existing coal-fired power plants or reduce construction of any new coal-fired power plants, which could have a material adverse effect on demand and prices received for our coal. 
An inability to acquire replacement coal reserves could adversely affect our ability to produce coal.
Our business, financial condition and results of operations depend substantially on obtaining coal reserves that have geological characteristics that enable them to be mined at competitive costs and to meet the coal quality needed by our customers. Because we deplete our reserves as we mine coal, our future success and growth will depend, in part, upon our ability to acquire additional coal reserves that are economically recoverable. Our current strategy includes increasing our coal reserves through acquisitions of other mineral rights, leases, or producing properties and continuing to use our existing properties. Our ability to expand our operations may be dependent on our ability to obtain sufficient working capital, either through cash flows generated from operations or financing activities, or both. If we fail to acquire or develop additional reserves, our existing reserves will eventually be depleted. Replacement reserves may not be available when required or, if available, may not be capable of being mined at costs comparable to those characteristic of the depleting mines. Exhaustion of reserves at particular mines with certain valuable coal characteristics also may have an adverse effect on our operating

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results that is disproportionate to the percentage of overall production represented by such mines. Our ability to obtain other reserves could be limited by restrictions under our existing credit facilities or future debt agreements. Our inability to obtain reserves could adversely affect our business, financial condition and/or results of operations.
We may not be able to successfully replace our reserves or grow through future acquisitions or organic growth projects.
From time to time, we may seek to expand our operations by adding new mines and reserves through strategic acquisitions or other organic growth projects, including dropdowns from our general partner, and we intend to continue expanding our operations and coal reserves through these transactions. Our future growth could be limited if we are unable to continue making acquisitions or conducting organic growth projects, or if we are unable to successfully integrate the companies, businesses or properties we acquire or that are contributed to us from our general partner. We may not be successful in consummating any such transactions and the consequences of undertaking these transactions are unknown. Our ability to conduct these transactions in the future could be limited by restrictions under our existing or future debt agreements, competition from other coal companies for attractive properties, the lack of suitable acquisition candidates, and regulatory restrictions on us or our general partner.
Our reserve estimates may prove to be incorrect.
The coal reserve estimates in this report are estimates based on the interpretation of limited sampling and subjective judgments regarding the grade, continuity and existence of mineralization, as well as the application of economic assumptions, including assumptions as to operating costs and future commodity prices. The sampling, interpretations or assumptions underlying any reserve estimate may be incorrect, and the impact on the amount of reserves ultimately proven to be recoverable may be material. Should the mineralization and/or configuration of a deposit ultimately turn out to be significantly different from that currently envisaged, then the proposed mining plan may have to be altered in a way that could affect the tonnage and grade of the reserves mined and rates of production and, consequently, could adversely affect the profitability of the mining operations. In addition, short term operating factors relating to the reserves, such as the need for orderly development of ore bodies or the processing of new or different ores, may cause reserve estimates to be modified or operations to be unprofitable in any particular fiscal period. There can be no assurance that our projects or operations will be, or will continue to be, economically viable, that the indicated amount of minerals will be recovered or that they will be recovered at the prices assumed for purposes of estimating reserves.
Any inaccuracies in our estimates of our coal reserves could result in decreased profitability from lower than expected revenues or higher than expected costs.
Our future performance depends on, among other things, the accuracy of our estimates of our proven and probable coal reserves. Our reserve estimates are prepared by our engineers and geologists or by third-party engineering firms and are updated periodically. There are numerous factors and assumptions inherent in estimating the quantities and qualities of, and costs to mine, coal reserves, including many factors beyond our control which include the following:
quality of the coal;
geological and mining conditions, which may not be fully identified by available exploration data and/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, taxes, including severance and excise taxes and royalties, and other payments to governmental agencies;
economic assumptions, including assumptions as to future commodity prices;
assumptions concerning the timing for the development of the 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 may vary materially due to changes in the above factors and assumptions. Any inaccuracy in our estimates related to our reserves could result in decreased profitability from lower than expected revenues or higher than expected costs.

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A defect in title or the loss of a leasehold interest in certain property could limit our ability to mine our coal reserves or result in significant unanticipated costs.
We conduct a significant part of our coal mining operations on properties that we lease. A title defect or the loss of a lease could adversely affect our ability to mine the associated coal reserves. We may not verify title to our leased properties or associated coal reserves until we have committed to developing those properties or coal reserves. We may not commit to develop property or coal reserves until we have obtained necessary permits and completed exploration. As such, the title to property that we intend to lease or coal reserves that we intend to mine may contain defects prohibiting our ability to conduct mining operations. Similarly, our leasehold interests may be subject to superior property rights of other third parties. In order to conduct our mining operations on properties where these defects exist, we may incur unanticipated costs. In addition, some leases require us to produce a minimum quantity of coal and require us to pay minimum production royalties. Our inability to satisfy those requirements may cause the leasehold interest to terminate.
We are dependent on information technology and our systems and infrastructure face certain risks, including cybersecurity risks and data leakage risks.
We are dependent on information technology systems and infrastructure. Any significant breakdown, invasion, destruction or interruption of these systems by employees, others with authorized access to our systems, or unauthorized persons could negatively impact operations. There is also a risk that we could experience a business interruption, theft of information, or reputational damage as a result of a cyber-attack, such as an infiltration of a data center, or data leakage of confidential information either internally or at our third-party providers. While we have invested in the protection of our data and information technology to reduce these risks and periodically test the security of our information systems network, there can be no assurance that our efforts will prevent breakdowns or breaches in our systems that could adversely affect our business.
Concerns regarding climate change are, in many of the places where we operate, leading to increasing interest in, and in some cases enactment of, laws and regulations governing greenhouse gas emissions, which affect the end-users of coal and could reduce the demand for coal as a fuel source and cause the volume of our sales and/or the prices we receive to decline. These laws and regulations also have imposed, and will continue to impose, costs directly on us.
GHG emissions have increasingly become the subject of international, national, state and local attention. Coal-fired power plants can generate large amounts of GHG emissions. Accordingly, legislation or regulation intended to limit GHGs will likely indirectly affect our coal operations by limiting our customers’ demand for our coal or reducing the prices we can obtain, and also may directly affect our own power operations. In the United States, the EPA has issued a determination that emissions of carbon dioxide, methane, nitrous oxide 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 federal Clean Air Act. The EPA implemented GHG-related reporting and permitting rules. Portions of the EPA’s GHG permitting rules, which were the subject of litigation by some industry groups and states, were recently struck down in part by the U.S. Supreme Court, but the EPA’s authority to impose GHG control technologies on a majority of large emissions sources, including coal-fired electric utilities, remain in place. President Obama in June 2013 announced a Climate Action Plan, which included a Presidential Memorandum directing the EPA to issue standards for GHG emissions from existing, modified and reconstructed fossil-fuel fired power plants. The EPA issued a revised proposal with standards for new fossil fuel-fired plants, including coal-fired plants, in September 2013, which the EPA plans to finalize by January 2015. The EPA also has released its “Clean Power Plan” in June 2014, which includes proposed standards for existing and modified sources. Under the Clean Power Plan as currently proposed, the EPA would set standards for existing sources as stringent state-specific carbon emission rates that, if finalized, would be phased in between 2020 and 2030. The proposed rule would give states the discretion to use a variety of approaches - including cap-and-trade programs - to meet the standard. The EPA estimates that the proposed existing source rule would reduce CO2 emissions from the power sector by 30 percent by 2030, with a focus on emissions from coal-fired generation. The EPA plans to finalize the rule by June 2015, and state plans are due by June 2016, with one- to two-year extensions available. The U.S. Congress has considered, and in the future may again consider, legislation governing GHG emission, including “cap and trade” legislation that would establish a cap on emissions of GHGs covering much of the economy in the United States and would require most sources of GHG emissions to obtain GHG emission “allowances” corresponding to their annual emissions of GHGs. In addition, coal-fired power plants, including new coal-fired power plants or capacity expansions of existing plants, have become subject to opposition by environmental groups seeking to curb the environmental effects of GHG emissions. It is difficult to predict at this time the effect these proposed rules would have on our revenues and profitability.

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Our inability to obtain and/or review permits necessary for our operations could prevent us from mining certain coal reserves.
The slowing pace at which permits are assigned or reviewed for new or existing mines is our area of operations has materially impacted production in Appalachia. Section 402 National Pollutant Discharge Elimination System permits and Section 404 of the CWA permits are required to discharge wastewater and dredged or fill material into waters of the United States. Our surface coal mining operations typically require such permits to authorize activities such as the creation of sediment ponds and the reconstruction of streams and wetlands impacted by our mining operations. Although the CWA gives the EPA a limited oversight role in the Section 404 permitting program, the EPA has recently asserted its authorities more forcefully to question, delay, and prevent issuance of some Section 404 permits for surface coal mining in Appalachia. Currently, significant uncertainty exists regarding the obtaining of permits under the CWA for coal mining operations in Appalachia due to various initiatives launched by the EPA regarding these permits. 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 which we operate. An inability to obtain the necessary permits to conduct our mining operations or an inability to comply with the requirements of applicable permits could reduce our production and cash flows, which could adversely affect our business, financial condition and/or results of operations and our cash flow.
For more information, please read “Part I, Item 1. Business - Environmental, Safety and Other Regulatory Matters.
Our coal mining operations are subject to external conditions that could disrupt operations and negatively affect our results of operations.
Our coal mining operations are all surface mines. These mines are subject to conditions or events beyond our control that could disrupt operations, affect production, and increase the cost of mining at particular mines for varying lengths of time. These conditions or events include: unplanned equipment failures; geological, hydrological or other conditions such as variations in the quality of the coal produced from a particular seam; variations in the thickness of coal seams and variations in the amounts of rock and other natural materials that overlie the coal that we are mining; weather conditions; competition and/or conflicts with other natural gas resource extraction activities and production within our operating areas; 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; accidental mine water flooding; labor-related interruptions; transportation delays in barge, rail and truck systems due to weather-related problems, mechanical difficulties, strikes, bottlenecks, and other events; mining and processing equipment unavailability and failures and unexpected maintenance problems; potential unionization of our workforce; and accidents, including fire and explosions from methane. Major disruptions in operations at any of our mines over a lengthy period could adversely affect the profitability of our mines. Any of these conditions may increase the cost of mining and delay or halt production at particular mines for varying lengths of time, which in turn could adversely affect our business, financial condition and/or results of operations.
Unplanned outages and extensions of scheduled outages due to mechanical failures or other problems occur from time to time at our power plant customers and are an inherent risk of our business. Unplanned outages typically increase our operation and maintenance expenses and may reduce our revenues due to selling fewer tons of coal. We maintain business interruption insurance coverage to lessen the impact of events such as this. However, business interruption insurance may not always provide adequate compensation for lost coal sales, and significant unanticipated outages at our power plant customers which result in lost coal sales could result in significant adverse effects on our operating results.
In general, mining accidents present a risk of various potential liabilities depending on the nature of the accident, the location, the proximity of employees or other persons to the accident scene and a range of other factors. Possible liabilities arising from a mining accident include workers’ compensation claims or civil lawsuits for workplace injuries, claims for personal injury or property damage by people living or working nearby, and fines and penalties including possible criminal enforcement against us and certain of our employees. In addition, a significant accident that results in a mine shutdown could give rise to liabilities for failure to meet the requirements of coal-supply agreements, especially if the counterparties dispute our invocation of the force majeure provisions of those agreements. We maintain insurance coverage to mitigate the risks of certain of these liabilities, but those policies are subject to various exclusions and limitations. We cannot assure you that we will receive coverage under those policies for any personal injury, or property damage that may arise out of such an accident. Currently, we do not carry business interruption insurance and we may not carry other types of insurance in the future. Moreover, certain potential liabilities, such as fines and penalties, are not insurable risks. Thus, a serious mine accident may result in material liabilities that adversely affect our business, financial condition and/or results of operations.

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Our operations are vulnerable to natural disasters, operating difficulties and infrastructure constraints, not all of which are covered by insurance, which could have an impact on our productivity.
Mining and power operations are vulnerable to natural events, including blizzards, earthquakes, drought, floods, fire, storms and the possible effects of climate change. Operating difficulties such as unexpected geological variations could affect the costs and viability of our operations. Our operations also require reliable roads, rail networks, power sources and power transmission facilities, water supplies and IT systems to access and conduct operations. The availability and cost of infrastructure affects our capital expenditures, operating costs, and planned levels of production and sales.
We maintain insurance for some, but not all, of the potential risks and liabilities associated with our business. For some risks, we may not obtain insurance if we believe the cost of available insurance is excessive relative to the risks presented. As a result of market conditions, premiums and deductibles for certain insurance policies can increase substantially, and in some instances, certain insurance may become unavailable or available only for reduced amounts of coverage. As a result, we may not be able to renew our existing insurance policies or procure other desirable insurance on commercially reasonable terms, if at all. Although we maintain insurance at levels we believe are appropriate and consistent with industry practice, we are not fully insured against all risks. In addition, pollution and environmental risks and consequences of any business interruptions such as equipment failure or labor disputes generally are not fully insurable. Losses and liabilities from uninsured and underinsured events and delay in the payment of insurance proceeds could have a material adverse effect on our financial condition, results of operations and cash flows.
Mining in Northern Appalachia and the Illinois Basin is more complex and involves more regulatory constraints than mining in other areas of the United States.
The geological characteristics of Northern Appalachian and Illinois Basin coal reserves, such as depth of overburden and coal seam thickness, make them complex and costly to mine. As mines become depleted, replacement reserves may not be available when required or, if available, may not be capable of being mined at costs comparable to those of the depleting mines. These factors could adversely affect our business, financial condition and/or results of operations.    
The assumptions underlying our reclamation and mine closure obligations could be materially inaccurate.
The Federal Surface Mining Control and Reclamation Act of 1977 and counterpart state laws and regulations establish operational, reclamation and closure standards for all aspects of surface mining, as well as most aspects of underground mining. Estimates of our total reclamation and mine closing liabilities are based upon permit requirements and our engineering expertise related to these requirements. While the estimate of our reclamation liability is reviewed regularly by our management, the estimate can change significantly if actual costs vary from assumptions or if governmental regulations change significantly. Such changes could adversely affect our business, financial condition and/or results of operations.
If the assumptions underlying our asset retirement obligations are materially inaccurate, we could be required to expend greater amounts than anticipated.
We are subject to stringent reclamation and closure standards for our mining operations. We calculate the total estimated asset retirement obligations, or ARO, for final reclamation and mine closure according to the guidance provided by GAAP and current industry practice. Estimates of our total ARO are based upon permit requirements and our engineering expertise related to these requirements. If our estimates are incorrect, we could be required in future periods to spend materially different amounts on reclamation and mine-closing activities than we currently estimate.
We estimate that our gross ARO, which is based upon projected mine lives, current mine plans, permit requirements and our experience, was $31.7 million (on a present value basis) at December 31, 2014. We must recover the costs incurred for these liabilities from revenues generated by coal sales.
Although we update our estimated costs annually, our recorded obligations may prove to be inadequate due to changes in legislation or standards and the emergence of new restoration techniques. Furthermore, the expected timing of expenditures could change significantly due to changes in commodity costs or prices that might curtail the life of an operation. These recorded obligations could prove insufficient compared to the actual cost of reclamation. Any underestimated or unidentified close down, restoration or environmental rehabilitation costs could have an adverse effect on our reputation as well as our asset values, results of operations and liquidity.

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For more information, please read "Part II, Item 7 - Management's Discussion and Analysis of Financial Condition and Results of Operations-Critical Accounting Policies and Estimates-Reclamation and Mine Closure Costs."
If the cost of obtaining new reclamation bonds and renewing existing reclamation bonds increases or if we are unable to obtain additional bonding capacity, our operating results could be negatively affected.
We are required to provide bonds to secure our obligations to reclaim lands used for mining. We must post a bond before we obtain a permit to mine any new area. These bonds are typically renewable on a yearly basis. Bonding companies are requiring that applicants collateralize increasing portions of their obligations to the bonding company. In 2014, we paid approximately $1.0 million in premiums for reclamation bonds. We anticipate that, as we permit additional areas for our mines, our bonding and collateral requirements could increase. Any cash that we provide to collateralize our obligations to our bonding companies is not available to support our other business activities. Our results of operations could be negatively affected if the cost of our reclamation bonding premiums and collateral requirements were to increase. Additionally, if we are unable to obtain additional bonding capacity due to cash flow constraints, we will be unable to begin mining operations in newly permitted areas, which would hamper our ability to efficiently meet our current customer contract deliveries, expand operations, and increase revenues.
Transportation impediments may hinder our current operations or future growth.
We depend upon barge, rail and truck systems to deliver coal to our customers.   Disruptions in transportation services due to weather-related problems, mechanical difficulties, strikes, lockouts, bottlenecks, and other events could impair our ability to deliver coal to our customers.  As we do not have long-term contracts with transportation providers to ensure consistent service, decreased performance levels over long periods of time could cause our customers to look to other sources for their coal needs.  In addition, increases in transportation costs, including the price of gasoline and diesel fuel, could make coal a less competitive source of energy when compared to alternative fuels or could make coal produced in one region of the United States less competitive than coal produced in other regions of the United States or abroad. Our inability to timely deliver coal due to rising transportation costs could have a material adverse effect on our business, financial condition and/or results of operations.
The unavailability of rail capacity could also hinder our future growth as we seek to sell coal into new markets. The current availability of rail cars is limited and at times unavailable because of repairs or improvements, or because of priority transportation agreements with other customers. If transportation is restricted or is unavailable, we may be unable to sell into new markets and, therefore, the lack of rail capacity could hamper our future growth.
It is possible that one or more states in which our coal is transported by truck may modify their laws to further limit truck weight limits.  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, which could have an adverse effect on our ability to increase or to maintain production and could adversely affect our revenues.
Decreased availability or increased costs of key equipment and materials could impact our cost of production and decrease our profitability.
We depend on reliable supplies of mining equipment, replacement parts and materials such as explosives, diesel fuel, tires and magnetite. The supplier base providing mining materials and equipment has been relatively consistent in recent years, although there continues to be consolidation, which has resulted in a limited number of suppliers for certain types of equipment and supplies. Any significant reduction in availability or increase in cost of any mining equipment or key supplies could adversely affect our operations and increase our costs, which could adversely affect our operating results and cash flows.
In addition, the prices we pay for these materials are strongly influenced by the global commodities market. Coal mines consume large quantities of commodities such as steel, copper, rubber products, explosives and diesel and other liquid fuels. A rapid or significant increase in the cost of these commodities could increase our mining costs because we have limited ability to negotiate lower prices, and in some cases, do not have a ready substitute.
We enter into forward-purchase contract arrangements for a portion of our anticipated diesel fuel and explosive needs. Additionally, some of our expected diesel fuel requirements are protected, in varying amounts, by diesel fuel

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escalation provisions contained in coal supply contracts with some of our customers, that allow for a change in the price per coal ton sold. Price changes typically lag the changes in diesel fuel costs by one quarter. While our strategy provides us protection in the event of price increases to our diesel fuel, it may also prevent us from the benefits of price decreases. If prices for diesel fuel decreased significantly below our forward-purchase contracts, we would lose the benefit of any such decrease.
We face intense competition to attract and retain employees.
We are dependent on retaining existing employees and attracting additional qualified employees to meet current and future needs. We face intense competition for qualified employees, and there can be no assurance that we will be able to attract and retain such employees or that such competition among potential employers will not result in increasing salaries. We rely on employees with unique skill sets to perform our mining operations, including engineers, mechanics and other highly skilled individuals. An inability to retain existing employees or attract additional employees, especially with mining skills and background, could have a material adverse effect on our business, cash flows, financial condition and results of operations.
Our workforce could become unionized in the future.
Currently, none of our employees are represented under collective bargaining agreements.  However, all of our workforce may not remain union-free in the future.  If some or all of our workforce were to become unionized, it could adversely affect our productivity and labor costs and increase the risk of work stoppages, all of which could adversely affect our business, financial condition and/or results of operations.
Extensive government regulations impose significant costs on our mining operations, and future regulations could increase those costs or limit our ability to produce and sell coal.
The coal mining industry is subject to increasingly strict regulation by federal, state and local authorities with respect to matters such as:
limitations on land use;
employee health and safety;
mandated benefits for retired coal miners;
mine permitting and licensing requirements;
reclamation and restoration of mining properties after mining is completed;
air quality standards;
discharges to water;
construction and permitting of facilities required for mining operations, including valley fills and other structures constructed in water bodies and wetlands;
protection of human health, plant life and wildlife;
management of the materials generated by mining operations and discharge of these materials into the environment;
effects of mining on groundwater quality and availability; and
remediation of contaminated soil, surface and groundwater.
We are required to prepare and present to governmental authorities data concerning the potential effects of any proposed exploration or production of coal on the environment and the public has statutory rights to submit objections to requested permits and approvals. Failure to comply with MSHA regulations may result in the assessment of administrative, civil and criminal penalties. Other governmental agencies may impose cleanup and site restoration costs and liens, issue injunctions to limit or cease operations, suspend or revoke permits and take other enforcement measures that could have the effect of limiting production from our operations. We may also incur costs and liabilities resulting from claims for damages to property or injury to persons arising from our operations. If we are pursued for any sanctions, costs and liabilities, our mining operations and, as a result, our results of operations, could be adversely affected.
United States federal and state regulatory agencies have the authority to temporarily or permanently close a mine following significant health and safety incidents, such as a fatality. In the event that these agencies order the closing any of our mines, our coal sales contracts may 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

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successful, we may have to purchase coal from third-party sources, if it is available, and potentially at prices higher than our cost to produce coal, to fulfill these obligations, and negotiate settlements with customers, which may include price and quantity reductions, the extension of time for delivery, or contract termination. Additionally, we may be required to incur capital expenditures to re-open any closed mines. These actions could adversely affect our business, financial condition and/or results of operations.
New legislation or regulations and orders may be adopted that may materially adversely affect our mining operations, our cost structure and/or our customers’ ability to use coal. New legislation or administrative regulations (or new judicial interpretations or administrative enforcement of existing laws and regulations), including proposals related to the protection of the environment that would further regulate and tax the coal industry, may also require us and/or our customers to change operations significantly or incur increased costs. These regulations, if proposed and enacted in the future, could have a material adverse effect on our financial condition and/or results of operations.
For more information, please read “Part I, Item 1 - Business-Environmental, Safety and Other Regulatory Matters.
Federal legislation could result in higher healthcare costs.
In March 2010, the Patient Protection and Affordable Care Act (the “PPACA”) was enacted, impacting our costs of providing healthcare benefits to our eligible active employees, with both short-term and long-term implications. In the short term, our healthcare costs could increase due to, among other things, an increase in the maximum age for covered dependents to receive benefits, changes to benefits for occupational disease related illnesses, the elimination of lifetime dollar limits per covered individual and restrictions on annual dollar limits per covered individual. In the long term, our healthcare costs could increase for these same reasons, as well as due to an excise tax on “high cost” plans, among other things. Implementation of this legislation is expected to extend through 2018.
Beginning in 2018, the PPACA will impose a 40% excise tax on employers to the extent that the value of their healthcare plan coverage exceeds certain dollar thresholds. We anticipate that certain governmental agencies will provide additional regulations or interpretations concerning the application of this excise tax. We will continue to evaluate the impact of the PPACA, including any new regulations or interpretations, in future periods.
Any increase in cost, as a result of legislation or otherwise, could adversely affect our business, financial condition and/or results of operations.
Mining operations are subject to extensive and costly environmental laws and regulations, and such current and future laws and regulations could materially increase our operating costs or limit our ability to produce and sell coal.
The coal mining industry is subject to numerous and extensive federal, state and local environmental laws and regulations, including laws and regulations pertaining to permitting and licensing requirements, air quality standards, plant and wildlife protection, reclamation and restoration of mining properties, the discharge of materials into the environment, the storage, treatment and disposal of wastes, protection of wetlands, surface subsidence from underground mining, and the effects that mining has on groundwater quality and availability. The costs, liabilities and requirements associated with these laws and regulations are significant, time-consuming and may delay commencement or continuation of our operations.
The possibility exists that new laws or regulations (or new judicial interpretations or enforcement of existing laws and regulations) could materially affect our mining operations and our business, financial condition and/or results of operations, either through direct impacts such as those regulating our existing mining operations, or indirect impacts such as those that discourage or limit our customers' use of coal. For example, the EPA and the U.S. Army Corps of Engineers have proposed a rule to clarify which waters and wetlands are subject to regulation under the CWA. A change in CWA jurisdiction and permitting requirements could increase or decrease our permitting and compliance costs. Additionally, in June 2013, President Obama issued a Climate Action Plan, which included a focus on methane reductions from coal mines. In January 2015, the Administration issued its methane strategy, but it did not include requirements for coal mines. Although we believe that we are in substantial compliance with existing laws and regulations, we may, in the future, experience violations that would subject us to administrative, civil and criminal penalties and a range of other possible sanctions. As a result, the consequences for any noncompliance may become more significant in the future.

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Existing and future laws and regulations regulating the emission of sulfur dioxide and other compounds could affect coal consumers and as a result reduce demand for our coal.
Federal, state and local laws and regulations extensively regulate the amount of sulfur dioxide, particulate matter, nitrogen oxides, mercury and other compounds emitted into the air from electric power plants and other consumers that burn our coal. These laws and regulations can require significant emission control expenditures, and various new and proposed laws and regulations may require further emission reductions and associated emission control expenditures. A certain portion of our coal has a medium to high sulfur content, which results in increased sulfur dioxide emissions when combusted and therefore the use of our coal imposes certain additional costs on customers. For example, in February 2012, EPA signed a rule to reduce emissions of mercury and toxic air pollutants from new and existing coal- and oil-fired electric utility steam generating units, often referred to as the MATS Rule. This rule was upheld by the U.S. Court of Appeals for the D.C. Circuit in April 2014. In April 2014, the U.S. Supreme Court upheld the EPA’s Cross-State Air Pollution Rule (“CSAPR”), which would require stringent reductions in emissions of nitrogen oxides and sulfur dioxide from power plants in much of the Eastern United States, including Texas and North Carolina, and in October 2014 the D. C. Circuit granted the EPA’s motion to lift the D.C. Circuit’s stay of the CSAPR, and remanded the case to the D.C. Circuit for further proceedings, which are ongoing. The EPA issued an interim rule in December 2014 that would require the first phase of reductions in 2015 and 2016, with the second phase of reductions beginning in 2017. Accordingly, these laws and regulations may affect demand and prices for our higher sulfur coal. A reduction in demand for our coal could adversely affect our business, financial condition and/or results of operations.
For more information, please read “Part I, Item 1 - Business — Environmental, Safety and Other Regulatory Matters — Air Emissions.”
Risks Inherent in an Investment in Us
Our partnership agreement limits our general partner’s fiduciary duties to our unitholders and restricts the remedies available to our unitholders for actions taken by our general partner that might otherwise constitute breaches of fiduciary duties.
Fiduciary duties owed to our unitholders by our general partner are prescribed by law and the partnership agreement. The Delaware Revised Uniform Limited Partnership Act (the “Delaware Act”) provides that Delaware limited partnerships may, in their partnership agreements, restrict the fiduciary duties owed by the general partner to limited partners and the partnership. Our partnership agreement contains such provisions. For example, our partnership agreement:
limits the liability and reduces the fiduciary duties of our general partner, while also restricting the remedies available to our unitholders for actions that, without these limitations, might constitute breaches of fiduciary duty. As a result of purchasing common units, our unitholders consent to some actions and conflicts of interest that might otherwise constitute a breach of fiduciary or other duties under applicable state law;
permits our general partner to make a number of decisions in its individual capacity, as opposed to in its capacity as our general partner. This entitles our general partner to consider only the interests and factors that it desires, and it has no duty or obligation to give any consideration to any interest of, or factors affecting, us, our affiliates or any limited partner. Examples include the exercise of its limited call right, its voting rights with respect to the units it owns, its registration rights and its determination whether or not to consent to any merger or consolidation of the partnership;
provides that our general partner shall not have any liability to us or our unitholders for decisions made in its capacity as general partner so long as it acted in good faith, meaning our general partner 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 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.

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By purchasing a common unit, a common unitholder will become bound by the provisions of our partnership agreement, including the provisions described above.
Our general partner and its affiliate may have conflicts of interest with us, and their limited fiduciary duties to our unitholders may permit them to favor their own interests to the detriment of our unitholders.
WCC owns common units representing a 79.0% limited partner interest in us as well as 100% of our general partner, which owns all of our outstanding 35,291 general partner units and incentive distribution rights. 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 WCC and its affiliates, including our general partner, on the one hand, and us and our unitholders, on the other hand. As a result of these conflicts, our general partner may favor its own interests and the interests of its affiliates over the interests of our unitholders. The risk to our unitholders due to such conflicts may arise because of the following factors, among others:
our general partner is allowed to take into account the interests of parties other than us, such as WCC, in resolving conflicts of interest, which has the effect of limiting its fiduciary duty to our unitholders;
neither our partnership agreement nor any other agreement requires owners of our general partner to pursue a business strategy that favors us. Executive officers and directors of our general partner’s owners have a fiduciary duty to make these decisions in the best interest of their owners, which may be contrary to our interests;
our general partner determines the amount and timing of asset purchases and sales, capital expenditures, borrowings and issuances of additional partnership securities and reserves, each of which can affect our financial condition;
our general partner determines which costs incurred by it and its affiliates are reimbursable by us;
our partnership agreement does not restrict our general partner from causing us to pay it or its affiliates for any services rendered on terms that are fair and reasonable to us or entering into additional contractual arrangements with any of these entities on our behalf;
our general partner intends to limit its liability regarding our contractual and other obligations;
our general partner may exercise its limited right to call and purchase common units if it and its affiliates own more than 80% of the common units which could cause unitholders to sell units at a time and price that may not be desirable;
our general partner controls the enforcement of obligations owed to us by it and its affiliates; and
our general partner decides whether to retain separate counsel, accountants or others to perform services for us.
In addition, WCC 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, WCC is not prohibited from engaging in other businesses or activities, including those that might be in direct competition with us. As a result, WCC could potentially compete with us for acquisition opportunities and for new business or extensions of the existing services provided by us.
Pursuant to the terms of our partnership agreement, the doctrine of corporate opportunity, or any analogous doctrine, does not apply to our general partner or any of its affiliates, including its executive officers, directors and owners. Any such person or entity that becomes aware of a potential transaction, agreement, arrangement or other matter that may be an opportunity for us will not have any duty to communicate or offer such opportunity to us. Any such person or entity will not be liable to us or to any limited partner for breach of any fiduciary duty or other duty by reason of the fact that such person or entity pursues or acquires such opportunity for itself, directs such opportunity to another person or entity or does not communicate such opportunity or information to us. This may create actual and potential conflicts of interest between us and affiliates of our general partner and result in less than favorable treatment of us and our unitholders.
For more information, please read “- Our partnership agreement limits our general partner’s fiduciary duties to our unitholders and restricts the remedies available to our unitholders for actions taken by our general partner that might otherwise constitute breaches of fiduciary duties.”

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Our unitholders have limited voting rights, are not entitled to elect our general partner or its directors and have limited ability to remove our general partner without its consent.
Unlike the holders of common stock in a corporation, our unitholders have only limited voting rights on matters affecting our business and, therefore, limited ability to influence management’s decisions regarding our business. Our unitholders have no right to elect our general partner or its board of directors on an annual or other continuing basis. The board of directors of our general partner is chosen entirely by its members and not by our unitholders. Furthermore, if our unitholders are dissatisfied with the performance of our general partner, they have limited ability to remove our general partner.
Our unitholders are unable to remove our general partner without its consent because affiliates of our general partner own sufficient units to be able to prevent removal of our general partner. The vote of the holders of at least 80% of all outstanding common units is required to remove our general partner. Our general partner owns 0.6% of our common units and the owner of our general partner, WCC, owns 79.0% of our outstanding equity interests.
Cause is narrowly defined in our partnership agreement to mean that a court of competent jurisdiction has entered a final, non-appealable judgment finding our general partner liable for actual fraud or willful misconduct in its capacity as our general partner. Cause does not include most cases of charges of poor management of the business, so the removal of our general partner during the subordination period because of our unitholders’ dissatisfaction with our general partner’s performance in managing our partnership will most likely result in the termination of the subordination period.
The control of our general partner may be transferred to a third party without unitholder consent.
Our general partner may transfer its general partner interest in us to a third party in a merger or in a sale of all or substantially all of its assets without the consent of our unitholders. Furthermore, there is no restriction in our partnership agreement on the ability of the members of our general partner to transfer their respective membership interests in our general partner to a third party. The new members of our general partner would then be in a position to replace the board of directors and executive officers of our general partner with their own choices and to control the decisions and actions of the board of directors and executive officers of our general partner.
The incentive distribution rights of our general partner may be transferred to a third party without unitholder consent.
Our general partner may transfer its incentive distribution rights to a third party at any time without the consent of our unitholders. If our general partner transfers its incentive distribution rights to a third party but retains its general partner interest, our general partner may not have the same incentive to grow our partnership and increase quarterly distributions to unitholders over time as it would if it had retained ownership of its incentive distribution rights.
Our general partner has a limited call right that may require our unitholders to sell their common units at an undesirable time or price.
At any time that our general partner and its affiliates own more than 80.0% of the common units, our general partner will have the right, but not the obligation, which it may assign to any of its affiliates or to us, to acquire all, but not less than all, of the common units held by unaffiliated persons at a price not less than the then-current market price.  As a result, our unitholders may be required to sell their common units at an undesirable time or price and may not receive any return on their investment.  Our unitholders may also incur a tax liability upon a sale of their common units.  Our general partner is not obligated to obtain a fairness opinion regarding the value of the common units to be repurchased by it upon exercise of the limited call right.  There is no restriction in our partnership agreement that prevents our general partner from issuing additional common units and exercising its limited call right.  If our general partner exercised its limited call right, the effect would be to take us private and, if the common units were subsequently deregistered, we would no longer be subject to the reporting requirements of the Securities Exchange Act of 1934, as amended (the “Exchange Act”).
We may issue additional units without unitholder approval.
At any time, we may issue an unlimited number of limited partner interests of any type without the approval of our unitholders. Further, our partnership agreement does not prohibit the issuance of equity securities that may effectively rank senior to our common units. The issuance by us of additional common units or other equity securities of equal or senior rank will have the following effects:

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our unitholders’ proportionate ownership interest in us will decrease;
the amount of cash available for distribution on each unit may decrease;
the relative voting strength of each previously outstanding unit may be diminished; and
the market price of the common units may decline.
Our general partner may, without unitholder approval, elect to cause us to issue common units and general partner units to it in connection with a resetting of the target distribution levels related to its incentive distribution rights.
Our general partner has the right, at any time when it has received distributions on its incentive distribution rights at the highest level to which it is entitled (48.0%) for each of the prior four consecutive fiscal quarters, to reset the initial target distribution levels at higher levels based on our distributions at the time of the exercise of the reset election. Following a reset election by our general partner, the minimum quarterly distribution will be adjusted to equal the reset minimum quarterly distribution and the target distribution levels will be reset to correspondingly higher levels based on percentage increases above the reset minimum quarterly distribution.
If our general partner elects to reset the target distribution levels, it will be entitled to receive a number of common units and general partner units. The number of common units to be issued to our general partner will be equal to that number of common units that would have entitled their holder to an average aggregate quarterly cash distribution in the prior two quarters equal to the average of the distributions to our general partner on the incentive distribution rights in the prior two quarters. Our general partner will be issued the number of general partner units necessary to maintain our general partner’s interest in us that existed immediately prior to the reset election. We anticipate that our general partner would exercise this reset right in order to facilitate acquisitions or internal growth projects that would not be sufficiently accretive to cash distributions per common unit without such conversion. It is possible, however, that our general partner could exercise this reset election at a time when it is experiencing, or expects to experience, declines in the cash distributions it receives related to its incentive distribution rights and may, therefore, desire to be issued common units rather than retain the right to receive distributions on its incentive distribution rights based on the initial target distribution levels. As a result, a reset election may cause our common unitholders to experience a reduction in the amount of cash distributions that our common unitholders would have otherwise received had we not issued new common units and general partner units to our general partner in connection with resetting the target distribution levels.
The market price of our common units could be impacted by sales of substantial amounts of our common units in the public markets, including sales by our existing unitholders.
A unitholder may sell some or all of our common units that it owns or it may distribute our common units to the holders of its equity interests and those holders may dispose of some or all of these units. The sale or disposition of a substantial number of our common units in the public markets could have a material adverse effect on the price of our common units or could impair our ability to obtain capital through an offering of equity securities. We do not know whether any such sales would be made in the public market or in private placements, nor do we know what impact such potential or actual sales would have on our unit price in the future.
An increase in interest rates may cause the market price of our common units to decline.
Like all equity investments, an investment in our common units is subject to certain risks. In exchange for accepting these risks, investors may expect to receive a higher rate of return than would otherwise be obtainable from lower-risk investments. Accordingly, as interest rates rise, the ability of investors to obtain higher risk-adjusted rates of return by purchasing government-backed debt securities may cause a corresponding decline in demand for riskier investments generally, including yield-based equity investments such as publicly-traded limited partnership interests. Reduced demand for our common units resulting from investors seeking other more favorable investment opportunities may cause the trading price of our common units to decline.
Cost reimbursements may be due to our general partner and its affiliates.
We will reimburse our general partner and its affiliates for all expenses they incur on our behalf, which will be determined by our general partner in its sole discretion in accordance with the terms of our partnership agreement. In determining the costs and expenses allocable to us, our general partner is subject to its fiduciary duty, as modified by our partnership agreement, to the limited partners, which requires it to act in good faith. These expenses include all costs incurred by our general partner and its affiliates in managing and operating us. We are managed and operated by executive officers and

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directors of our general partner. The reimbursement of expenses and payment of fees, if any, to our general partner and its affiliates will reduce our cash.
Our unitholders may have liability to repay distributions.
Under certain circumstances, our unitholders may have to repay amounts wrongfully returned or distributed to them. Under Section 17-607 of the Delaware Act, we may not make a distribution to our unitholders if the distribution would cause our liabilities to exceed the fair value of our assets. Delaware law provides that, for a period of three years from the date of the impermissible distribution, limited partners who received the distribution and who knew at the time of the distribution that it violated Delaware law will be liable to the limited partnership for the distribution amount. Purchasers of units who become limited partners are liable for the obligations of the transferring limited partner to make contributions to the partnership that are known to the purchaser of units at the time it became a limited partner and for unknown obligations if the liabilities could be determined from our partnership agreement. Liabilities to partners on account of their partnership interests and liabilities that are non-recourse to the partnership are not counted for purposes of determining whether a distribution is permitted.
Common units held by unitholders who are not eligible citizens will be subject to redemption.
Our general partner may require each limited partner to furnish information about his nationality, citizenship or related status. If a limited partner fails to furnish information about his nationality, citizenship or other related status within 30 days after a request for the information or our general partner determines after receipt of the information that the limited partner is not an eligible citizen, the limited partner may be treated as a non-citizen assignee. A non-citizen assignee does not have the right to direct the voting of his units and may not receive distributions in kind upon our liquidation. Furthermore, we have the right to redeem all of the common units of any holder that is not an eligible citizen or fails to furnish the requested information. The redemption price will be paid in cash or by delivery of a promissory note, as determined by our general partner.
In order to comply with U.S. laws with respect to the ownership of interests in mineral leases on federal lands, we have adopted certain requirements regarding those investors who own our common units. As used in this report, an eligible citizen means a person or entity qualified to hold an interest in mineral leases on federal lands. As of the date hereof, an eligible citizen must be: (1) a citizen of the United States; (2) a corporation organized under the laws of the United States or of any state thereof; or (3) an association of U.S. citizens, such as a partnership or limited liability company, organized under the laws of the United States or of any state thereof, but only if such association does not have any direct or indirect foreign ownership, other than foreign ownership of stock in a parent corporation organized under the laws of the United States or of any state thereof. For the avoidance of doubt, onshore mineral leases or any direct or indirect interest therein may be acquired and held by aliens only through stock ownership, holding or control in a corporation organized under the laws of the United States or of any state thereof. Unitholders who are not persons or entities who meet the requirements to be an eligible citizen run the risk of having their units redeemed by us at the lower of their purchase price cost or the then-current market price. The redemption price will be paid in cash or by delivery of a promissory note, as determined by our general partner.
Tax Risks to Common Unitholders
Our tax treatment depends on our status as a partnership for federal income tax purposes, as well as our being subject to minimal entity-level taxation by individual states. If the Internal Revenue Service, or IRS, were to treat us as a corporation for federal income tax purposes, or we become subject to a material amount of entity-level taxation for state tax purposes, it would substantially reduce the amount of cash available for distribution to our unitholders.
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. Although we do not believe based upon our current operations that we will be treated as a corporation, the IRS could disagree with the positions we take or 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.

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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%, and would likely pay state and local income tax at varying rates. Distributions to a unitholder 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 the unitholder. Because a tax would be imposed upon us as a corporation, our cash available for distribution to a unitholder would be substantially reduced. Therefore, if we were treated as a corporation for federal tax purposes there could be a material reduction in the anticipated cash flow and after-tax return to a unitholder, likely causing a substantial reduction in the value of our common units.
We are subject to extensive tax laws and regulations, with respect to federal, state and foreign income taxes and transactional taxes such as excise, sales/use, payroll, franchise and ad valorem taxes. New tax laws and regulations and changes in existing tax laws and regulations are continuously being enacted that could result in increased tax expenditures in the future. Further, changes in current state law may subject us to additional entity-level taxation by individual states. Because of widespread state budget deficits and other reasons, several states are evaluating ways to subject partnerships to entity-level taxation through the imposition of state income, franchise and other forms of taxation. Imposition of any such taxes could adversely affect our cash available for distribution to unitholders.
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 will 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 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. Any modification to the federal income tax laws and interpretations thereof may or may not be applied retroactively. Moreover, any such modification could make it more difficult or impossible for us to meet the exception that allows publicly traded partnerships that generate qualifying income to be treated as partnerships (rather than corporations) for federal income tax purposes, affect or cause us to change our business activities, or affect the tax consequences of an investment in our common units. For example, members of the U.S. Congress have considered, and the Administration has proposed, substantive changes to the existing federal income tax laws that would affect the tax treatment of certain publicly traded partnerships. 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.
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 (the “Budget Proposal”) is the elimination of certain key U.S. federal income tax preferences relating to coal exploration and development. The Budget Proposal would have: (i) eliminated current deductions, the 60-month amortization period and the 10-year amortization period for exploration and development costs relating to coal and other hard mineral fossil fuels, (ii) repealed the percentage depletion allowance with respect to coal properties, (iii) repealed capital gains treatment of coal and lignite royalties and (iv) excluded from the definition of domestic production gross receipts all gross receipts derived from the production of coal and other hard mineral fossil fuels. The passage of any legislation effecting changes similar to those in the Budget Proposal in federal income tax laws could eliminate certain tax deductions that are currently available with respect to coal exploration and development, and any such change could increase the taxable income allocable to our unitholders and negatively impact the value of an investment in our common units.
If tax authorities contest the tax positions we take, the market for our common units could be adversely impacted, and the cost of any contest with a tax authority would 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. Tax authorities may adopt positions that differ from the positions we take, and a tax authority’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. A court may not agree with some or all of the positions we take. Any contest with a tax authority, and the outcome of any such contest, may increase a unitholder’s tax liability and result in adjustment to items

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unrelated to us and could materially and adversely impact the market for our common units and the price at which they trade. The rights of a unitholder owning less than a 1% profits interest in us to participate in the federal income tax audit process are very limited. In addition, our costs of any contest with any tax authority will be borne indirectly by our unitholders and our general partner because such costs will reduce our cash available for distribution.
Our unitholders may be required to pay taxes on income from us even if the unitholders 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 tax liability that results from that income.
Certain actions that we may take, such as issuing additional units, may increase the federal income tax liability of unitholders.
In the event we issue additional units or engage in certain other transactions in the future, the allocable share of nonrecourse liabilities allocated to the unitholders will be recalculated to take into account our issuance of any additional units. Any reduction in a unitholder’s share of our nonrecourse liabilities will be treated as a distribution of cash to that unitholder and will result in a corresponding tax basis reduction in a unitholder’s units. A deemed cash distribution may, under certain circumstances, result in the recognition of taxable gain by a unitholder, to the extent that the deemed cash distribution exceeds such unitholder’s tax basis in its units.
In addition, the federal income tax liability of a unitholder could be increased if we dispose of assets or make a future offering of units and use the proceeds in a manner that does not produce substantial additional deductions, such as to repay indebtedness currently outstanding or to acquire property that is not eligible for depreciation or amortization for federal income tax purposes or that is depreciable or amortizable at a rate significantly slower than the rate currently applicable to the our assets.
Tax gain or loss on the disposition of common units could be more or less than expected.
If a unitholder sells its common units, the unitholder will recognize a gain or loss equal to the difference between the amount realized and the unitholder’s tax basis in those common units. Because distributions to a unitholder in excess of the total net taxable income allocated to it for a common unit decreases its tax basis in that common unit, the amount, if any, of such prior excess distributions with respect to the units sold will, in effect, become taxable income to the unitholder if the common unit is sold at a price greater than its tax basis in that common unit, even if the price is less than the original cost. Furthermore, a substantial portion of the amount realized, 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 a unitholder sells its common units, the unitholder may incur a tax liability in excess of the amount of cash the unitholder receives from the sale.
Tax-exempt entities and non-U.S. persons face unique tax issues from owning common units that may result in adverse tax consequences to them.
Investment in common units by tax-exempt entities, such as individual retirement accounts, or IRAs, other retirement plans 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, which may 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 federal tax returns and pay tax on their share of our taxable income. If a unitholder is a tax-exempt entity or a non-U.S. person, the unitholder should consult its tax advisor before investing in our common units.
We treat each purchaser of our common units as having the same tax benefits without regard to the actual common units purchased. The IRS may challenge this treatment, which could adversely affect the value of 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

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successful IRS challenge to those positions could adversely affect the amount of tax benefits available to the unitholders. It also could affect the timing of these tax benefits or the amount of gain from the sale of common units and could have a negative impact on the value of common units or result in audit adjustments to unitholders’ tax returns.
We prorate our items of income, gain, loss and deduction 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 unitholders.
We prorate our items of income, gain, loss and deduction 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. Although 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 among transferor and transferee unitholders, such regulations are not final and do not specifically authorize the use of the proration method we have adopted. If the IRS were to challenge our proration 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 cover a short sale of common units may be considered as having disposed of those common units. If so, the unitholder would no longer be treated for tax purposes as a partner with respect to those 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 cover a short sale of common units may be considered as having disposed of the loaned common units, the unitholder may no longer be treated for 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. 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 modify any applicable brokerage account agreements to prohibit their brokers from borrowing and lending their common units.
We have adopted certain valuation methodologies that may result in a shift of income, gain, loss and deduction between our general partner and the unitholders. The IRS may challenge this treatment, which could adversely affect the value of the common units.
When we issue additional common units or engage in certain other transactions, we determine the fair 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, 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 income, gain, loss and deduction between our general partner and certain of the 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 gain from our unitholders’ sale of common units and could have a negative impact on the value of the common units or result in audit adjustments to our unitholders’ tax returns without the benefit of additional deductions.
The sale or exchange of 50% or more of our capital and profits interests during any twelve-month period will result in the termination of our partnership for federal income tax purposes.
We will be considered to have terminated as a 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. Our termination, among other things, would 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 Schedule K-1s if relief from the IRS was not granted, as described below) for one calendar year. Our termination could also result in a significant deferral of depreciation deductions allowable in computing our taxable income. In the case of a unitholder reporting on a taxable year other than a calendar year, the closing

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of our taxable year may result in more than twelve months of our taxable income or loss being includable in its taxable income for the year of termination. Under current law, such a termination would not affect our classification as a partnership for federal income tax purposes, but instead, after our termination, 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 announced a relief procedure for publicly traded partnerships that terminate in this manner, whereby if a publicly traded partnership that has terminated requests and the IRS grants special relief, among other things, we will only have to provide one Schedule K-1 to unitholders for the year, notwithstanding two partnership tax years resulting from the termination.
Unitholders may be subject to state and local taxes and return filing requirements in states and localities where they do not reside or own properties.
In addition to federal income taxes, unitholders may be subject to other taxes, including foreign, state and local taxes, unincorporated business taxes and estate, inheritance or intangible taxes that are imposed by the various jurisdictions in which we do business or own property now or in the future, even if the unitholders do not live in any of those jurisdictions. Unitholders may be required to file foreign, state and local income tax returns and pay state and local income taxes in some or all of these jurisdictions. Further, unitholders may be subject to penalties for failure to comply with those requirements. As we make acquisitions or expand our business, we may own assets or do business in additional states that impose a personal income tax or an entity level tax. It is each unitholder’s responsibility to file all federal, foreign, state and local tax returns. Our counsel has not rendered an opinion on the state, local or non-U.S. tax consequences of an investment in common units.
Some of the states in which we do business or own property may require us to, or we may elect to, withhold a percentage of income from amounts to be distributed to a unitholder who is not a resident of the state. Withholding, the amount of which may be greater or less than a particular unitholder’s income tax liability to the state generally, does not relieve the nonresident unitholder from the obligation to file an income tax return. Amounts withheld may be treated as if distributed to unitholders for purposes of determining the amounts distributed by us.
Item 1B.Unresolved Staff Comments
None.

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Item 2.Properties
Mining Operations
See “Part I, Item 1 - Business - Operations” for specific information about our mining operations.
Coal Reserves
We base our coal reserve estimates on engineering, economic and geological data assembled and analyzed by our staff. These estimates are also based on the expected cost of production and projected sale prices and assumptions concerning permitability. The estimates of coal reserves as to both quantity and quality are periodically updated to reflect the production of coal from the reserves, updated geologic models and mining recovery data, coal reserves recently acquired and estimated costs of production and sales prices. Changes in mining methods may increase or decrease the recovery basis for a coal seam as will plant processing efficiency tests.
Periodically, we retain outside experts to independently verify our coal reserve and our non-reserve coal deposit estimates. At December 31, 2014, an audit review of our coal reserves, other than the Kemmerer reserves, was completed by John T. Boyd Company, an independent mining and geological consulting firm. The Kemmerer reserve estimates were completed by WCC's engineers and geologist. WCC compiled data from individual drill holes in a database from which the depth, thickness and the quality of the coal are determined.
As of December 31, 2014, we owned 37.5% of our coal reserves and leased 62.5% of our coal reserves from various third parties. As of December 31, 2014, we controlled an estimated 106.5 million tons of proven and probable coal reserves, including 54.7 million tons of coal reserves we have leased or subleased to others.
The following table provides information as of December 31, 2014 on the location of our operations and the amount and ownership of our coal reserves:
 
 
Total Proven and Probable Coal Reserves
Mining Complex
 
Total
 
Owned
 
Leased
 
 
(tons in thousands)
Surface Mining Operations:
 
 
 
 
 
 
Northern Appalachia (principally Ohio):
 
 
 
 
 
 
Cadiz
 
7,891

 
5,911

 
1,980

Tuscarawas County
 
5,966

 
118

 
5,848

Plainfield
 
3,447

 
737

 
2,710

Belmont County
 
10,741

 
922

 
9,819

New Lexington
 
6,117

 
429

 
5,688

Noble County
 
1,327

 

 
1,327

Illinois Basin (Kentucky):
 


 


 


Muhlenberg County
 
16,296

 
1,473

 
14,823

Total Surface Mining Operations
 
51,785

 
9,590

 
42,195

 
 
 
 
 
 
 
Coal Reserves Leased to Others:
 
 
 
 
 
 
Kemmerer(1)
 
30,354

 
30,354

 

Tusky
 
24,331

 

 
24,331

Total Coal Reserves Leased to Others
 
54,685

 
30,354

 
24,331

Total
 
106,470

 
39,944

 
66,526

Percentage of Total
 
100
%
 
37.5
%
 
62.5
%
(1)
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. 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.

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The following table provides information on particular characteristics of our coal reserves as of December 31, 2014.
 
 
As Received Basis(1)
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Lbs. of
SO2/mm 
Btu
 
Proven and Probable Coal Reserves
 
 
 
 
 
 
 
 
 
Sulfur Content(1)
Mining Complex
 
Btu/lb.
 
% Ash
 
% Sulfur
 
 
<2%
 
2-4%
 
>4%
 
Total
 
 
 
 
 
 
 
 
 
 
(tons in thousands)
Surface Mining Operations:
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Northern Appalachia (principally Ohio):
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Cadiz
 
11,350

 
13.0
%
 
2.7
%
 
4.7

 
2,903

 
3,754

 
1,234

 
7,891

Tuscarawas County
 
11,775

 
10.3
%
 
4.1
%
 
6.9

 
815

 
1,304

 
3,847

 
5,966

Plainfield
 
11,703

 
9.7
%
 
4.4
%
 
7.6

 

 
765

 
2,682

 
3,447

Belmont County
 
11,804

 
12.8
%
 
4.3
%
 
7.3

 

 
2,398

 
8,343

 
10,741

New Lexington
 
11,177

 
12.7
%
 
4.1
%
 
7.3

 

 
2,341

 
3,776

 
6,117

Noble County
 
11,239

 
10.9
%
 
4.8
%
 
8.6

 

 

 
1,327

 
1,327

Illinois Basin (Kentucky):
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Muhlenberg County
 
11,314

 
11.3
%
 
3.6
%
 
6.4

 

 
15,884

 
412

 
16,296

Total Surface Mining Operations
 
 
 
 

 
 
 
 

 
3,718

 
26,446

 
21,621

 
51,785

 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Coal Reserves Leased to Others:
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Kemmerer
 
9,818

 
4.7
%
 
0.64
%
 
1.3

 
30,354

 

 

 
30,354

Tusky
 
12,900

 
5.3
%
 
2.1
%
 
3.2

 
3,768

 
20,563

 

 
24,331

Total Coal Reserves Leased to Others
 
 
 
 
 
 
 
 
 
34,122

 
20,563

 

 
54,685

Total
 
 
 
 
 
 
 
 
 
37,840

 
47,009

 
21,621

 
106,470

(1)
As received represents an analysis of a sample as received at a laboratory operated by a third party.
Office and Warehouse Facilities
We own a 30,000 square feet warehouse in Zanesville, Ohio that serves all our Northern Appalachian mines. We have leased office space in Columbus, Ohio for our executives and related administrative support staff. Our lease in Columbus, Ohio expires February 28, 2015. In addition, we own buildings, primarily for our administrative support and operational support staffs, located in Coshocton, Ohio and 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. 
In November 2014 we entered into a plea agreement regarding, and in December 2014 the United States filed and we pleaded guilty to, a single count misdemeanor information in the United States District Court for the Southern District of Ohio, Eastern Division. The information filing alleged negligent violation of a condition and limitation of a National Pollutant Discharge Elimination System permit. This matter arose from our voluntary disclosure of the filing of false reports by a rogue employee who was terminated shortly after his false reporting was discovered. We are subject to a probationary period of 6-12 months and are paying a fine of $500,000 and community service payments of $150,000.
Item 4.Mine Safety Disclosures
Information concerning mine safety violations or other regulatory matters required by Section 1503(a) of the Dodd-Frank Act and Item 104 of Regulation S-K for the year ended December 31, 2014 is included as Exhibit 95 to this Annual Report on Form 10-K.

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WESTMORELAND RESOURCE PARTNERS, LP AND SUBSIDIARIES

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PART II
Item 5.Market for Registrant’s Common Equity, Related Unitholder Matters and Issuer Purchases of Equity Securities
The common units of Westmoreland Resource Partners, LP are trading on the NYSE under the symbol "WMLP." On March 3, 2015, the closing market price for our common units was $11.25 per unit.
As of March 3, 2015, we had outstanding 5,711,636 common units, 856,698 liquidation units and 35,291 general partner units. We also had outstanding warrants to purchase an aggregate of 166,735 common units. There were approximately 32 record holders of common units on December 31, 2014. 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 liquidation units and general partner units, for which there is no established public trading market, are held by WCC. The liquidation units have no distribution rights or voting rights, other than in connection with liquidation.
The following table sets forth the range of the daily high and low sales prices for the periods indicated:
Period
High Price
 
Low Price
 
First Quarter 2013
$
73.32

 
$
25.32

 
Second Quarter 2013
$
41.40

 
$
25.20

 
Third Quarter 2013
$
34.32

 
$
22.80

 
Fourth Quarter 2013
$
23.88

 
$
12.96

 
 
 
 
 
 
First Quarter 2014
$
18.60

 
$
13.20

 
Second Quarter 2014
$
18.24

 
$
9.00

 
Third Quarter 2014
$
13.20

 
$
8.64

 
Fourth Quarter 2014
$
16.68

 
$
7.32

 
Reverse Unit Split
In December 2014 our unitholders approved a 12-to-1 reverse unit split of the common units, which was effected on December 31, 2014. Unitholders' equity and all references to unit and per unit amounts herein and in the accompanying consolidated financial statements have been retroactively adjusted to reflect the 12-to-1 reverse unit split for all periods presented.
Subordinated Units Conversion to Liquidation Units
All subordinated units were transferred to WCC in connection with the WCC transactions on December 31, 2014. These units were then converted to liquidation units which have no distribution or voting rights, other than in connection with liquidation. For tax purposes, liquidation units are allocated additional taxable income but no additional taxable loss compared to other unit classes.
Cash Distributions
No cash dividends were declared or paid during 2014 or 2013 on any class of our partnership units. We currently anticipate that we will reinstate quarterly distributions on our common units some time in 2015.
Cash Distribution Arrearage
In December 2014 our partnership agreement was amended, with unitholder approval, to waive and eliminate our then existing cumulative common unit arrearages and also eliminate the concept of common unit arrearages going forward.

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WESTMORELAND RESOURCE PARTNERS, LP AND SUBSIDIARIES

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Cash Distribution Policies
Our partnership agreement requires that we distribute all of our available cash quarterly. Under our partnership agreement, available cash is generally defined to mean, for each quarter, cash generated from our business in excess of the amount of cash reserves established by our general partner to provide for the conduct of our business, to comply with applicable law to make payments related to any of our debt instruments or other agreements, or to provide for future distributions to our unitholders for any one or more of the next four quarters. Our available cash may also include, if our general partner so determines, all or any portion of the cash on hand on the date of determination of available cash for the quarter resulting from working capital borrowings made subsequent to the end of such quarter.
Our general partner, who is wholly owned by WCC, is entitled to 0.6% of all quarterly distributions that we make prior to our liquidation. This general partner interest is represented by 35,291 general partner units. Our general partner also currently holds incentive distribution rights that entitle it to receive increasing percentages of distributions over certain amounts, up to a maximum of 48.0% of the cash we distribute from operating surplus in excess of $0.2000 per unit per quarter. The maximum distribution of 48.0% is in addition to the distributions paid to our general partner on its 0.6% general partner interest.
In December 2014, we closed on a new $295 million credit facility that replaced our previous term loan and revolving credit facilities, which new credit facility has customary financial and other covenants, including restrictions on our ability to make distributions. See “Item 7 - Management’s Discussion and Analysis of Financial Condition and Results of Operations -Recent Developments - Credit Facilities.
Unregistered Sales of Equity Securities
In December 2014, in connection with the WCC transactions, (i) all 151,182 of the subordinated unit warrants, which were held by certain former lenders and lender affiliates, were canceled and (ii) 3,585 common unit warrants were issued to certain former lenders and lender affiliates, plus 4,512,500 common units were issued to WCC in consideration for its contribution to us of WKFCH. These transactions were exempt from registration pursuant to Section 4(2) of the Securities Act of 1933, as amended.
Issuer Purchases of Equity Securities.
During 2014, we did not make any purchases of our common units and no such purchases were made on our behalf.
Securities Authorized for Issuance Under Equity Compensation Plan
Please read the information in this Annual Report on Form 10-K under “Part II, Item 12 - Security Ownership of Certain Beneficial Owners and Management and Related Unitholder Matters,” which is incorporated by reference into this Item 5.

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WESTMORELAND RESOURCE PARTNERS, LP AND SUBSIDIARIES

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Item 6.Selected Financial and Operating Data
The following table presents our selected financial and operating data 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.”
WCC's cost of acquiring our GP has been pushed-down to establish a new accounting basis for us. Accordingly, the accompanying consolidated financial statements are presented for two periods, Predecessor and Successor, which relate to the accounting periods preceding and succeeding the completion of the acquisition. The Predecessor and Successor periods have been separated by a vertical line on the face of the consolidated financial statements to highlight the fact that the financial information for such periods has been prepared under two different historical-cost bases of accounting. The following narrative analysis of results of operations includes a brief discussion of the factors that materially affected our operating results in the Predecessor period of January 1 - December 31, 2014 along with a brief discussion of Successor activity for the last minutes of the day on December 31, 2014. 

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WESTMORELAND RESOURCE PARTNERS, LP AND SUBSIDIARIES

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SELECTED FINANCIAL AND OPERATING DATA
 
Westmoreland
Resource
Partners, LP
 
 
Oxford Resource Partners, LP
 
(Successor)(1)
 
 
(Predecessor)
 
Period of
December 31,
2014
 
 
Period from
January 1,
2014
through
December 31,
2014
 
Year Ended December 31,
 
 
 
 
2013
 
2012
 
2011
 
2010
 
 
 
 
(in thousands)
STATEMENT OF OPERATIONS DATA:
 
 
 
 
 
 
 
 
 
 
 
 
Revenues:
 
 
 
 
 
 
 
 
 
 
 
 
Coal revenues
$

 
 
$
295,662

 
$
336,201

 
$
364,928

 
$
391,046

 
$
350,057

Royalty revenues

 
 
284

 
8

 
1,496

 
3,202

 
2,790

Non-coal revenues

 
 
26,317

 
10,558

 
7,103

 
6,129

 
5,579

Total Revenues

 
 
322,263

 
346,767

 
373,527

 
400,377

 
358,426

Costs and expenses:
 
 
 
 
 
 
 
 
 
 

 
 

Cost of coal revenues

 
 
258,575

 
290,427

 
312,467

 
330,111

 
286,374

Cost of non-coal revenues

 
 
1,700

 
1,619

 
1,195

 
1,742

 
2,380

Depreciation, depletion and amortization

 
 
39,315

 
48,081

 
51,170

 
51,905

 
42,329

Selling and administrative

 
 
20,510

 
17,297

 
15,629

 
13,739

 
17,257

(Gain) loss on sales of assets

 
 
(218
)
 
(6,488
)
 
(8,021
)
 
1,352

 
1,228

Restructuring and impairment charges
2,783

 
 
75

 
1,761

 
15,650

 

 

Total cost and expenses
2,783

 
 
319,957

 
352,697

 
388,090

 
398,849

 
349,568

Operating (loss) income
(2,783
)
 
 
2,306

 
(5,930
)
 
(14,563
)
 
1,528

 
8,858

Other (expense) income:
 
 
 
 
 
 
 
 
 
 
 
 
Interest expense

 
 
(27,787
)
 
(20,246
)
 
(11,500
)
 
(9,870
)
 
(8,209
)
Interest income

 
 
4

 
4

 
10

 
13

 
12

(Loss) gain on debt extinguishment
(1,623
)
 
 
500

 
(808
)
 

 

 
(1,302
)
Change in fair value of warrants

 
 
822

 
3,280

 

 

 

Total other expenses
(1,623
)
 
 
(26,461
)
 
(17,770
)
 
(11,490
)
 
(9,857
)
 
(9,499
)
Net loss
(4,406
)
 
 
(24,155
)
 
(23,700
)
 
(26,053
)
 
(8,329
)
 
(641
)
Less net loss attributable to noncontrolling interest

 
 
1,270

 
(1,225
)
 
(755
)
 
(4,748
)
 
(6,710
)
Net loss attributable to WMLP unitholders
(4,406
)
 
 
(22,885
)
 
(24,925
)
 
(26,808
)
 
(13,077
)
 
(7,351
)
Less net loss allocated to general partners
(28
)
 
 
(429
)
 
(497
)
 
(535
)
 
(261
)
 
(147
)
Net loss allocated to limited partners
$
(4,378
)
 
 
$
(22,456
)
 
$
(24,428
)
 
$
(26,273
)
 
$
(12,816
)
 
$
(7,204
)
(1)See Note 3: Acquisition and Pushdown Accounting included in the notes to the consolidated financial statements included in “Item 8 - Financial Statements and Supplementary Data.”

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WESTMORELAND RESOURCE PARTNERS, LP AND SUBSIDIARIES

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Westmoreland
Resource
Partners, LP
 
 
Oxford Resource Partners, LP
 
(Successor) (4)
 
 
(Predecessor)
 
Period of
December 31,
2014
 
 
Period from
January 1,
2014
through
December 31,
2014
 
Year Ended December 31,
 
 
 
 
2013
 
2012
 
2011
 
2010
 
 
 
 
(in thousands, except per ton amounts)
STATEMENT OF CASH FLOWS DATA:
 
 
 
 
 
 
 
 
 
 
 
 
Cash flows from:
 
 
 
 
 
 
 
 
 
 
 
 
Operating activities
$
(1,820
)
 
 
$
24,385

 
$
9,716

 
$
31,776

 
$
43,951

 
$
34,900

Investing activities

 
 
(8,253
)
 
(22,463
)
 
(8,059
)
 
(31,914
)

(74,723
)
Financing activities
7,741

 
 
(19,221
)
 
11,859

 
(22,772
)
 
3,954

 
47,784

 
 
 
 
 
 
 
 
 
 
 
 
 
OTHER FINANCIAL DATA:
 
 
 
 
 
 
 
 
 
 
 
 
Adjusted EBITDA (1)
$

 
 
$
36,296

 
$
42,107

 
$
47,917

 
$
58,785

 
$
58,327

Capital expenditures (2)

 
 
15,938

 
20,297

 
24,476

 
39,047

 
92,133

Cash reclamation expenditures

 
 
4,354

 
8,222

 
8,966

 
5,491

 
2,419

 
 
 
 
 
 

 
 
 
 
 
 
OPERATING DATA:
 
 
 
 
 
 
 
 
 
 
 
 
Produced tons

 
 
5,553

 
6,147

 
6,817

 
8,078

 
7,417

Purchased tons

 
 
78

 
455

 
533

 
380

 
734

Tons of coal sold

 
 
5,631

 
6,602

 
7,350

 
8,458

 
8,151

 
 
 
 
 
 
 
 
 
 
 
 
 
  Tons sold under long-term contracts (3)
%
 
 
96.8
%
 
96.7
%
 
95.9
%
 
96.6
%
 
95.9
%
 
 
 
 
 
 
 
 
 
 
 
 
 
Coal sales revenue per ton
$

 
 
$
52.50

 
$
50.93

 
$
49.65

 
$
46.23

 
$
42.95

Below-market sales contract amortization per ton

 
 

 
(0.01
)
 
(0.08
)
 
(0.11
)
 
(0.17
)
Cash coal sales revenue per ton

 
 
52.50

 
50.92

 
49.57

 
46.12

 
42.78

Cash cost of coal revenues per ton

 
 
(45.92
)
 
(43.99
)
 
(42.51
)
 
(39.02
)
 
(35.13
)
Cash margin per ton
$

 
 
$
6.58

 
$
6.93

 
$
7.06

 
$
7.10

 
$
7.65

(1) 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."
(2) Includes $33.2 million related to the contribution of the Kemmerer coal reserves by WCC on December 31, 2014.
(3) Represents the percentage of the tons of coal we sold that were delivered under long-term coal sales contracts..
(4) See Note 3: Acquisition and Pushdown Accounting included in the notes to the consolidated financial statements included in “Item 8 - Financial Statements and Supplementary Data.”
Non-GAAP Financial Measures
Reconciliation of Adjusted EBITDA to Net Loss
EBITDA and Adjusted EBITDA are supplemental measures of financial performance that are not required by, or presented in accordance with, GAAP. EBITDA and Adjusted EBITDA are key metrics used by us to assess our operating performance and we believe that EBITDA and Adjusted EBITDA are useful to an investor in evaluating our operating performance because these measures:
are used widely by investors to measure a company’s operating performance without regard to items excluded from the calculation of such terms, which can vary substantially from company to company depending upon accounting methods and book value of assets, capital structure and the method by which assets were acquired, among other factors; and

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WESTMORELAND RESOURCE PARTNERS, LP AND SUBSIDIARIES

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help investors to more meaningfully evaluate and compare the results of our operations from period to period by removing the effect of our capital structure and asset base from our operating results.
Neither EBITDA nor Adjusted EBITDA is a measure calculated in accordance with GAAP. The items excluded from EBITDA and Adjusted EBITDA are significant in assessing our operating results. EBITDA and Adjusted EBITDA have limitations as analytical tools, and should not be considered in isolation from, or as a substitute for, analysis of our results as reported under GAAP. For example, EBITDA and Adjusted EBITDA:
do not reflect our cash expenditures, or future requirements for capital and major maintenance expenditures or contractual commitments;
do not reflect changes in, or cash requirements for, our working capital needs; and
do not reflect the significant interest expense, or the cash requirements necessary to service interest or principal payments, on certain of our debt obligations.
In addition, although depreciation and amortization are non-cash charges, the assets being depreciated and amortized will often have to be replaced in the future, and EBITDA and Adjusted EBITDA do not reflect any cash requirements for such replacements. Other companies in our industry and in other industries may calculate EBITDA and Adjusted EBITDA differently from the way that we do, limiting their usefulness as comparative measures. Because of these limitations, EBITDA and Adjusted EBITDA should not be considered as measures of discretionary cash available to us to invest in the growth of our business. We compensate for these limitations by relying primarily on our GAAP results and using EBITDA and Adjusted EBITDA only as supplemental data.
The tables below show how we calculated EBITDA and Adjusted EBITDA and reconciles Adjusted EBITDA to net loss, the most directly comparable GAAP financial measure. 
Reconciliation of Net Loss to Adjusted EBITDA
 
Westmoreland
Resource
Partners, LP
 
 
Oxford Resource Partners, LP
 
(Successor)(1)
 
 
(Predecessor)
 
Period of
December 31,
2014
 
 
Period from
January 1,
2014
through
December 31,
2014
 
Year Ended December 31,
 
 
 
 
2013
 
2012
 
2011
 
2010
 
 
 
 
(in thousands)
Reconciliation of Net Loss to Adjusted EBITDA
 
 
 
 
 
 
 
 
 
 
 
 
Net loss
$
(4,406
)
 
 
$
(24,155
)
 
$
(23,700
)
 
$
(26,053
)
 
$
(8,329
)
 
$
(641
)
Loss (gain) on extinguishment of debt
1,623

 
 
(500
)
 
808

 

 

 

Interest expense, net of interest income

 
 
27,783

 
20,242

 
11,490

 
9,857

 
9,499

Depreciation, depletion and amortization

 
 
39,070

 
47,847

 
50,855

 
51,560

 
41,941

Accretion of ARO and receivable

 
 
2,337

 
2,293

 
1,567

 
3,355

 
5,742

Amortization of intangible assets and liabilities

 
 
245

 
174

 
(308
)
 
(594
)
 
(1,036
)
EBITDA
(2,783
)
 
 
44,780

 
47,664

 
37,551

 
55,849

 
55,505

Restructuring and impairment charges
2,783

 
 
75

 
1,761

 
15,650

 

 

Legal settlements

 
 
(17,548
)
 
(2,100
)
 

 

 

Debt refinancing expenses

 
 

 
3,109

 

 

 
 
Recapitalization costs

 
 
5,470

 

 

 

 

Change in fair value of warrants

 
 
(822
)
 
(3,280
)
 

 

 

Sale of oil and gas rights

 
 
(232
)
 
(6,116
)
 
(6,329
)
 

 

(Gain)/loss on sale of assets

 
 
14

 
(372
)
 
(1,692
)
 
1,352

 
1,228

Share-based compensation

 
 
4,559

 
1,441

 
1,262

 
1,077

 
942

Other non-recurring costs

 
 

 

 
1,475

 
507

 
652

Adjusted EBITDA
$

 
 
$
36,296

 
$
42,107

 
$
47,917

 
$
58,785

 
$
58,327

(1) See Note 3: Acquisition and Pushdown Accounting included in the notes to the consolidated financial statements included in “Item 8 - Financial Statements and Supplementary Data.”

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WESTMORELAND RESOURCE PARTNERS, LP AND SUBSIDIARIES

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Item 7.Management’s Discussion and Analysis of Financial Condition and Results of Operations
The following discussion contains forward-looking statements that include numerous risks and uncertainties. Actual results could differ materially from those discussed in the forward-looking statements as a result of these risks and uncertainties, including those set forth in this Annual Report on Form 10-K under “Risk Factors.” You should read the following discussion in conjunction with “Selected Financial and Operating Data” and the audited consolidated financial statements and notes thereto of Westmoreland Resource Partners, LP and its subsidiaries appearing elsewhere in this Annual Report on Form 10-K.
Overview
We are a low-cost producer and marketer of high-value thermal coal to U.S. utilities and industrial users, and we are the largest producer of surface mined coal in Ohio. We focus on acquiring thermal coal reserves that we can efficiently mine with our large-scale equipment. Our reserves and operations are strategically located to serve our primary market area of Indiana, Kentucky, Michigan, Ohio, Pennsylvania and West Virginia. 
We operate in a single business segment and have four operating subsidiaries, Oxford Mining Company, LLC, Oxford Mining Company-Kentucky, LLC, Westmoreland Kemmerer Fee Coal Holdings, 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 of the subsidiaries other than WKFCH share common customers, assets and employees. 
Currently, we have 13 active surface mines and manage these mines as six mining complexes. Our operations also include a river terminal, strategically located in eastern Ohio. For the year ended December 31, 2014, we generated revenues of $322.3 million and had a net loss of $28.6 million. For the year ended December 31, 2014, we produced 5.5 million tons of coal, purchased less than 0.1 million tons of coal, and sold 5.6 million tons of coal. Of the coal tons sold, 96.8% were sold pursuant to long-term coal supply contracts. 
Recent Developments
In December 2014, WCC acquired our general partner and contributed WKFCH to us in exchange for common units. In connection with these transactions, we also restructured our partnership agreement, refinanced our existing credit facilities and issued a one-time 25% unit dividend. For more information, please read Item 1 - Business - Westmoreland Coal Company Transactions.
Evaluating Our Results of Operations 
We evaluate our results of operations based on several key measures, which include. 
our coal production, sales volume and sales prices, which drive our coal sales revenue;
our cost of coal revenues, including cost of purchased coal;
our net (loss) income; and
our Adjusted EBITDA, a non-GAAP financial measure.
Coal Production, Sales Volume and Sales Prices (Predecessor)
We evaluate our operations based on the volume of coal we produce, the volume of coal we sell, and the prices we receive for our coal. The volume of coal we sell is also a function of the productive capacity of our mining complexes, the amount of coal we purchase, and market demand. We sell substantially all of our coal under long-term coal sales contracts, and thus sales prices are dependent upon the terms of those contracts. Please read "— Cost of Coal Revenues" for more information regarding our purchased coal.
Our long-term coal sales contracts typically provide for fixed prices, or a schedule of prices that are either fixed or contain market-based adjustments, over the contract term. In addition, many of our long-term coal sales contracts have full or partial cost pass through or cost adjustment provisions. Cost pass through provisions increase or decrease the coal sales price for all or a specified percentage of changes in the costs for items such as fuel and inflation. Cost adjustment provisions adjust the initial contract price over the term of the contract either by a specific percentage or a percentage determined by reference to various cost-related indices, including cost-related indices for fuel and the cost-of-living generally.

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WESTMORELAND RESOURCE PARTNERS, LP AND SUBSIDIARIES

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We evaluate the price we receive for our coal on a per ton basis. Our coal sales revenue per ton represents our coal sales revenue divided by total tons of coal sold. The following table provides operational data including data with respect to our coal production and purchases, coal sold and coal sales revenue per ton for the periods indicated. 
 
Oxford Resource Partners, LP (Predecessor)
 
% Change
 
Period from
January 1, 2014
through
December 31,
2014
 
Year Ended December 31,
 
 2014
vs.
2013
 
2013
vs.
2012
 
 
2013
 
2012
 
 
 
(in thousands)
 
 
 
 
Tons of coal sold :
 
 
 
 
 
 
 
 
 
Produced tons
5,553

 
6,147

 
6,817

 
(9.7
)%
 
(9.8
)%
Purchased tons
78

 
455

 
533

 
(82.9
)%
 
(14.6
)%
Total
5,631

 
6,602

 
7,350

 
(14.7
)%
 
(10.2
)%
 
 
 
 
 
 
 
 
 
 
Tons sold under long-term contracts (1)
96.8
%
 
96.7
%
 
95.9
%
 
n/a

 
n/a

 
 
 
 
 
 
 
 
 
 
Coal sales revenue per ton
$
52.50

 
$
50.93

 
$
49.65

 
3.1
 %
 
2.6
 %
Below-market sales contract amortization per ton

 
(0.01
)
 
(0.08
)
 
(100.0
)%
 
(87.5
)%
Cash coal sales revenue per ton
52.50

 
50.92

 
49.57

 
3.1
 %
 
2.7
 %
Cash cost of coal revenues per ton
(45.92
)
 
(43.99
)
 
(42.51
)
 
4.4
 %
 
3.5
 %
Cash margin per ton
$
6.58

 
$
6.93

 
$
7.06

 
(5.1
)%
 
(1.8
)%
 
(1)
Represents the percentage of the tons of coal we sold that were delivered under long-term coal sales contracts.
Cost of Coal Revenues (Predecessor)
We evaluate, on a cost per ton sold basis, our cost of coal revenues which excludes non-cash costs such as DD&A, gain/loss on asset disposals, restructuring and impairment charges, and indirect costs such as selling and administrative expenses. Our cost of coal revenues per ton represents our cost of coal revenues divided by the tons of coal sold. Our cost of coal revenues includes costs for labor, fuel, oil, explosives, royalties, equipment lease expense, repairs and maintenance, and other costs directly related to our mining operations.
We purchase coal from third parties to fulfill a portion of our obligations under our long-term coal sales contracts and, in certain cases, to meet customer coal quality specifications. These costs are included in the cost of purchased coal amount within cost of coal revenues.
The following table provides summary information for the periods indicated relating to our cost of coal revenues per ton, produced tons, purchased tons and tons of coal sold. 
 
Oxford Resource Partners, LP (Predecessor)
 
% Change
 
Period from January 1, 2014 through December 31, 2014
 
Year Ended December 31,
 
2014
vs.
2013
 
2013
vs.
2012
 
 
2013
 
2012
 
 
 
(tons in thousands)
 
 
 
 
Cost of coal revenues per ton
$
45.92

 
$
43.99

 
$
42.51

 
4.4
 %
 
3.5
 %
 
 
 
 
 
 
 
 
 
 
Tons of coal sold:
 
 
 
 
 
 
 
 
 
  Produced tons
5,553

 
6,147

 
6,817

 
(9.7
)%
 
(9.8
)%
  Purchased tons
78

 
455

 
533

 
(82.9
)%
 
(14.6
)%
    Total
5,631

 
6,602

 
7,350

 
(14.7
)%
 
(10.2
)%


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Adjusted EBITDA
For a definition of EBITDA and Adjusted EBITDA and a reconciliation of net loss 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 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 restructuring and impairment charges resulting from the actions taken with respect to our Illinois Basin operations as described above under "Overview." For additional information regarding restructuring and impairment charges, refer to Note 4: Restructuring and Impairment Charges 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, 2014, 2013 and 2012
SELECTED FINANCIAL AND OPERATING DATA
 
Westmoreland
Resource
Partners, LP
 
 
Oxford Resource Partners, LP
 
(Successor)(1)
 
 
(Predecessor)
 
Period of
December 31,
2014
 
 
Period from
January 1,
2014
through
December 31,
2014
 
Year Ended December 31,
 
 
 
 
2013
 
2012
 
 
 
 
(in thousands)
STATEMENT OF OPERATIONS DATA:
 
 
 
 
 
 
 
 
Revenues:
 
 
 
 
 
 
 
 
Coal revenues
$

 
 
$
295,662

 
$
336,201

 
$
364,928

Royalty revenues

 
 
284

 
8

 
1,496

Non-coal revenues

 
 
26,317

 
10,558

 
7,103

Total Revenues

 
 
322,263

 
346,767

 
373,527

Costs and expenses:
 
 
 
 
 
 
 
 
Cost of coal revenues

 
 
258,575

 
290,427

 
312,467

Cost of non-coal revenues

 
 
1,700

 
1,619

 
1,195

Depreciation, depletion and amortization

 
 
39,315

 
48,081

 
51,170

Selling and administrative

 
 
20,510

 
17,297

 
15,629

(Gain) loss on sales of assets

 
 
(218
)
 
(6,488
)
 
(8,021
)
Restructuring and impairment charges
2,783

 
 
75

 
1,761

 
15,650

 
2,783

 
 
319,957

 
352,697

 
388,090

Operating (loss) income
(2,783
)
 
 
2,306

 
(5,930
)
 
(14,563
)
Other (expense) income:
 
 
 
 
 
 
 
 
Interest expense

 
 
(27,787
)
 
(20,246
)
 
(11,500
)
Interest income

 
 
4

 
4

 
10

(Loss) gain on debt extinguishment
(1,623
)
 
 
500

 
(808
)
 

Change in fair value of warrants

 
 
822

 
3,280

 

Total other expenses
(1,623
)
 
 
(26,461
)
 
(17,770
)
 
(11,490
)
Net loss
(4,406
)
 
 
(24,155
)
 
(23,700
)
 
(26,053
)
Less net loss (income) attributable to noncontrolling interest

 
 
1,270

 
(1,225
)
 
(755
)
Net loss attributable to WMLP unitholders
$
(4,406
)
 
 
$
(22,885
)
 
$
(24,925
)
 
$
(26,808
)
(1) See Note 3: Acquisition and Pushdown Accounting included in the notes to the consolidated financial statements included in “Item 8 - Financial Statements and Supplementary Data.”


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The following table presents a Reconciliation of Net Loss to Adjusted EBITDA for the years ended December 31, 2014, 2013 and 2012.
Reconciliation of Net Loss to Adjusted EBITDA(1):
 
Westmoreland
Resource
Partners, LP
 
 
Oxford Resource Partners, LP
 
(Successor)(1)
 
 
(Predecessor)
 
Period of
December 31,
2014
 
 
Period from
January 1,
2014
through
December 31,
2014
 
Year Ended December 31,
 
 
 
 
2013
 
2012
 
 
 
 
(in thousands)
Reconciliation of Net Loss to Adjusted EBITDA
 
 
 
 
 
 
 
 
Net loss
$
(4,406
)
 
 
$
(24,155
)
 
$
(23,700
)
 
$
(26,053
)
Loss (gain) on extinguishment of debt
1,623

 
 
(500
)
 
808

 

Interest expense, net of interest income

 
 
27,783

 
20,242

 
11,490

Depreciation, depletion and amortization

 
 
39,070

 
47,847

 
50,855

Accretion of ARO and receivable

 
 
2,337

 
2,293

 
1,567

Amortization of intangible assets and liabilities

 
 
245

 
174

 
(308
)
EBITDA
(2,783
)
 
 
44,780

 
47,664

 
37,551

Restructuring and impairment charges
2,783

 
 
75

 
1,761

 
15,650

Legal settlements

 
 
(17,548
)
 
(2,100
)
 

Debt refinancing expenses

 
 

 
3,109

 

Recapitalization costs

 
 
5,470

 

 

Change in fair value of warrants

 
 
(822
)
 
(3,280
)
 

Sale of oil and gas rights

 
 
(232
)
 
(6,116
)
 
(6,329
)
(Gain)/loss on sale of assets

 
 
14

 
(372
)
 
(1,692
)
Share-based compensation

 
 
4,559

 
1,441

 
1,262

Other non-recurring costs

 
 

 

 
1,475

Adjusted EBITDA
$

 
 
$
36,296

 
$
42,107

 
$
47,917

(1) See Note 3: Acquisition and Pushdown Accounting included in the notes to the consolidated financial statements included in “Item 8 - Financial Statements and Supplementary Data.”
Period of December 31, 2014 (Successor)
Restructuring and Impairment Charges
Restructuring and impairment charges were $2.8 million for the period year ended December 31, 2014, due to severance compensation resulting from the WCC transactions.
Period of January 1, 2014 through December 31, 2014 Compared to Year Ended December 31, 2013 (Predecessor)  
Overview
Total revenue was $322.3 million for the year ended December 31, 2014, a decrease of $24.5 million, or 7.1%, from $346.8 million for the year ended December 31, 2013. Net loss for the year ended December 31, 2014 was $24.2 million, compared to a net loss for the year ended December 31, 2013 of $23.7 million. Adjusted EBITDA was $36.3 million for the year ended December 31, 2014, a decrease of $5.8 million from $42.1 million for the year ended December 31, 2013. Cash margin per ton was $6.58 for the year ended December 31, 2014, a decrease of $0.35, or 5.1%, per ton from $6.93 per ton for the year ended December 31, 2013

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Coal Sales Revenues
Coal sales revenue was $295.7 million for the year ended December 31, 2014, a decrease of $40.5 million, or 12.1%, from $336.2 million for the year ended December 31, 2013. The decrease was primarily attributable to a 14.7% reduction in sales tons in the amount of $49.4 million that was a result of the lower sales volume from the Illinois Basin operations, partially offset by a $1.58 per ton, or an aggregate $8.9 million, increase in the average sale price per ton for the year ended December 31, 2014. 
Royalty Revenues
For the year ended December 31, 2014, we generated $0.3 million in royalty revenue from the receipt of oil and gas royalties. We did not generate any oil and gas royalty revenues for the year ended December 31, 2013.
In connection with WCC's contribution of WKFCH to us, WKFCH entered into a coal mining lease with a subsidiary of WCC pursuant to which we will earn a per ton royalty as the reserves owned by WKFCH are mined. Through the coal leasing agreement, 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 through December 31, 2020 and $0.5 million per quarter through December 31, 2025. For the year ended December 31, 2014, we did not recognize any royalty revenue on the lease of the Kemmerer coal reserves.
Non-coal Revenues
Non-coal revenues, primarily from clay and limestone sales, and other miscellaneous revenue was $26.3 million for the year ended December 31, 2014, an increase of $15.7 million, from $10.6 million for the year ended December 31, 2013. Other miscellaneous revenue increased by $15.3 million to $20.5 million for the year ended December 31, 2014 from $5.2 million in the prior year, due primarily to the receipt of $19.5 million in litigation settlement proceeds from a former customer compensating us for lost profits on coal sales due to a wrongfully terminated coal supply agreement. Other miscellaneous revenue for the year ended December 31, 2013 was primarily the result of one-time payments totaling $2.4 million for lost coal in connection with granting third-party right-of-way access through small portions of various mines and a $2.1 million settlement payment from a former coal supplier supporting sales from our Illinois Basin operations made pursuant to a settlement agreement entered into in February 2013. The $15.3 million increase in miscellaneous revenue was enhanced by a $0.4 million increase in clay and limestone sales to $5.8 million for the year ended December 31, 2014 from $5.4 million for the year ended December 31, 2013.
Cost of Coal Revenues
Cost of coal revenues (excluding DD&A) was $258.6 million for the year ended December 31, 2014, a decrease of $31.8 million, or 11.0%, from $290.4 million for the year ended December 31, 2013. The decrease was primarily attributable to a reduction of 1.0 million in tons sold, which corresponds to a $42.7 million decrease in cost of coal revenues, partially offset by an increase in the cost to produce coal of $1.93 per ton, or an aggregate $10.9 million, for the year ended December 31, 2014. Cost of coal revenues per ton was $45.92 for the year ended December 31, 2014, an increase of $1.93, or 4.4%, per ton from $43.99 per ton for the year ended December 31, 2013. The $1.93 per ton increase was primarily attributable to a $2.14 per ton, or $12.1 million, increase in labor expense, a $1.20 per ton, or $6.8 million, increase in transportation expense, and a $0.55 per ton, or $3.1 million, increase in diesel fuel expense, partially offset by a $3.02 per ton, or $17.0 million, decrease in purchased coal. Transportation expense increased due to longer haul routes, wages increased as the labor market became more competitive due to the growing oil and gas drilling business in southeastern Ohio, and diesel fuel expense increased due to fulfilling fuel contracts at contract prices while the diesel fuel price fell in the second half of 2014.
For the year ended December 31, 2014, 78 thousand tons of coal were purchased, which represents a decrease of 377 thousand tons of coal purchased from 455 thousand tons of coal purchased for the year ended December 31, 2013. In the year ended December 31, 2013, we had in place a purchased coal contract that allowed us to substitute lower cost purchased coal for mined and washed coal on certain sales contracts in the Illinois Basin. In the year ended December 31, 2014, we were no longer supplying those sales contracts and therefore did not enter into any such new purchase coal contracts. The aggregate cost for tons of coal purchased for the year ended December 31, 2014 decreased by $20.2 million from the year ended December 31, 2013.

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Depreciation, Depletion and Amortization
DD&A expense was $39.3 million for the year ended December 31, 2014, a decrease of $8.8 million, or 18.2%, from $48.1 million for the year ended December 31, 2013. Depreciation expense decreased $4.1 million, or 13.3%, to $26.7 million for the year ended December 31, 2014, from $30.8 million for the year ended December 31, 2013, which decrease was primarily attributable to the restructuring related to our Illinois Basin operations. Amortization expense was $7.3 million for the year ended December 31, 2014, a $5.5 million decrease from $12.8 million for the year ended December 31, 2013. The decrease was primarily attributable to changes in the amortization for asset retirement costs based on revisions to cost estimates and useful lives. Depletion expense was $5.3 million for the year ended December 31, 2014, a $0.8 million increase from $4.5 million for the year ended December 31, 2013, which was primarily attributable to an increase in the depletion rate per ton.
Selling and Administrative
Selling and administrative expenses were $20.5 million for the year ended December 31, 2014, an increase of $3.2 million, or 18.6%, from $17.3 million for the year ended December 31, 2013. The increase is primarily the result of one-time expenses resulting from the WCC transactions which includes $2.0 million in equity-based compensation expense related to change of control provisions for the LTIP. 
Restructuring and Impairment Charges
Restructuring and impairment charges were $0.1 million for the year ended December 31, 2014, a decrease of $1.7 million from $1.8 million for the year ended December 31, 2013. The year ended December 31, 2014 included $0.1 million in various inconsequential costs associated with the restructuring related to our Illinois Basin operations. The year ended December 31, 2013 included $1.8 million of restructuring expenses consisting of equipment transportation costs, employee severance costs, and coal lease termination costs associated with the restructuring relating to our Illinois Basin operations. Such restructuring was completed during the first quarter of 2014.
(Gain) Loss on Disposal of Assets, Net
The net gain on disposal of assets of $0.2 million for the year ended December 31, 2014 resulted from the disposal of equipment in the normal course of business. During the year ended December 31, 2013, the net gain of $6.5 million is primarily attributable to the sale of certain oil and gas rights resulting in net gains of $6.1 million. Additionally, $3.0 million in insurance proceeds was received on equipment lost in mining activities with a carrying value of $1.6 million, resulting in a $1.4 million gain for the year ended December 31, 2013. These gains were offset by net losses generated from the disposal of equipment in the normal course of business of $1.0 million for the prior year. 
Net Income Attributable to Noncontrolling Interest
Effective October 1, 2014, our subsidiary 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.
Net income attributable to noncontrolling interest relates to the 49% ownership interest in Harrison Resources owned by a subsidiary of CONSOL through September 30, 2014. Net loss attributable to noncontrolling interest was $1.3 million for the year ended December 31, 2014, a decrease of $2.5 million from net income attributable to noncontrolling interest of $1.2 million for the year ended December 31, 2013. This decrease in net income attributable to noncontrolling interest was primarily due to lower operating margins at the Harrison mine.
Year Ended December 31, 2013 Compared to Year Ended December 31, 2012 (Predecessor)
Overview
Total revenue was $346.8 million for the year ended December 31, 2013, a decrease of $26.7 million, or 7.2%, from $373.5 million for the year ended December 31, 2012. Net loss for the year ended December 31, 2013 was $23.7 million, compared to a net loss for the year ended December 31, 2012 of $26.1 million. Adjusted EBITDA was $42.1 million for the year ended December 31, 2013, a decrease of $5.8 million from $47.9 million for the year ended December 31, 2012. Cash margin per ton was $6.93 for the year ended December 31, 2013, a decrease of $0.13, or 1.8%, per ton from $7.06 per ton for

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the year ended December 31, 2012
Coal Sales Revenues 
Coal sales revenue was $336.2 million for the year ended December 31, 2013, a decrease of $28.7 million, or 7.9%, from $364.9 million for the year ended December 31, 2012. The decrease was primarily attributable to a 10.2% reduction in sales tons in the amount of $37.1 million that was a result of the lower sales volume from the Illinois Basin operations, partially offset by a $1.27 per ton, or an aggregate $8.4 million, increase in the average sale price per ton for the year ended December 31, 2013. 
Royalty Revenues
For the year ended December 31, 2012, we generated $1.5 million in royalty revenue from the receipt of coal royalties. We did not generate any royalty revenues for the year ended December 31, 2013 due to a temporary cessation of production at an underground mine leased to a third party.
Non-coal Revenues 
Non-coal revenues, primarily from clay and limestone sales, and other miscellaneous revenue, was $10.6 million for the year ended December 31, 2013, an increase of $3.5 million, or 48.6%, from $7.1 million for the year ended December 31, 2012. Other miscellaneous revenue increased $4.2 million to $5.2 million for the year ended December 31, 2013 from $1 million for the year ended December 31, 2012, due primarily to one-time payments totaling $2.4 million for lost coal in connection with granting third-party right-of-way access through small portions of various mines and a $2.1 million settlement payment from a former coal supplier supporting sales from our Illinois Basin operations made pursuant to a settlement agreement entered into in February 2013. The $4.2 million increase in other miscellaneous revenue was offset by a $0.7 million decrease in clay and limestone sales. Clay and limestone sales were $5.4 million for the year ended December 31, 2013, a decrease of $0.7 million, or 11.5%, from $6.1 million for the year ended December 31, 2012.  
Cost of Coal Revenues
Cost of coal revenues (excluding DD&A) was $290.4 million for the year ended December 31, 2013, a decrease of $22.1 million, or 7.1%, from $312.5 million for the year ended December 31, 2012. The decrease was primarily attributable to a reduction of 0.7 million in tons sold, which corresponds to a $31.9 million decrease in cost of coal revenues, partially offset by an increase in the cost to produce coal of $1.48 per ton, or an aggregate $9.8 million, for the year ended December 31, 2013. Cost of coal revenues per ton was $43.99 for the year ended December 31, 2013, an increase of $1.48, or 3.5%, per ton from $42.51 per ton for the year ended December 31, 2012. The $1.48 per ton increase was primarily attributable to a $0.76 per ton, or $5.0 million, increase in transportation expense, a $0.44 per ton, or $2.9 million, increase in tire expense, a $0.32 per ton, or $2.1 million, increase in wages, a $0.27 per ton, or $1.8 million, increase in explosives and a $0.16 per ton, or $1.1 million, increase in purchased coal, partially offset by a $0.20 per ton, or $1.3 million, decrease in diesel fuel expense. Transportation expense increased due to longer haul routes, wages increased as the labor market became more competitive due to the growing oil and gas drilling business in southeastern Ohio, and diesel fuel expense decreased due to lower spot prices. 
For the year ended December 31, 2013, 455 thousand tons of coal were purchased at an average price of $49.04 per ton, which represents a decrease of 78 thousand tons purchased at an increased cost of $4.62 per ton, or $2.1 million, compared to 533 thousand tons of coal purchased at an average price of $44.42 per ton for the year ended December 31, 2012
Depreciation, Depletion and Amortization 
DD&A expense was $48.1 million for the year ended December 31, 2013, a decrease of $3.1 million, or 6.0%, from $51.2 million for the year ended December 31, 2012. Depreciation expense decreased $3.5 million, or 10.2%, to $30.8 million for the year ended December 31, 2013 from $34.3 million for the year ended December 31, 2012, which decrease was primarily attributable to the restructuring related to our Illinois Basin operations. Depletion expense was $4.5 million for the year ended December 31, 2013, a $0.4 million decrease from $4.9 million for the year ended December 31, 2012, which decrease was primarily attributable to producing 0.7 million fewer tons of coal for the year ended December 31, 2013 compared to the year ended December 31, 2012. These decreases in depreciation and depletion expense were offset in part by a $0.8 million increase in amortization expense for the year ended December 31, 2013. The increase in amortization expense of $0.8 million, to $12.8 million, for the year ended December 31, 2013 was primarily attributable to an increase in the estimated cost of reclamation work. 

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WESTMORELAND RESOURCE PARTNERS, LP AND SUBSIDIARIES

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Selling and Administrative
Selling and administrative expenses were $17.3 million for the year ended December 31, 2013, an increase of $1.7 million, or 10.7%, from $15.6 million for the year ended December 31, 2012. The increase includes $3.1 million of fees, primarily for advisor and legal services, related to a refinancing of our credit facility, offset in part by decreases in employee benefits and contract labor expenses. Employee benefits decreased as no discretionary employer retirement plan contribution was provided for in the year ended December 31, 2013
Restructuring and Impairment Charges
Restructuring and impairment charges were $1.8 million for the year ended December 31, 2013, a decrease of $13.9 million from $15.7 million for the year ended December 31, 2012. The year ended December 31, 2013 included $1.8 million of restructuring expenses consisting of equipment transportation costs, employee severance costs, and coal lease termination costs associated with the restructuring relating to our Illinois Basin operations. The year ended December 31, 2012 included $2.9 million of similar restructuring expenses and $12.8 million in asset impairment charges. 
(Gain) Loss on Disposal of Assets, Net 
The net gain on disposal of assets of $6.5 million for the year ended December 31, 2013 represents a decrease of $1.5 million from a net gain on disposal of assets of $8.0 million for the year ended December 31, 2012. The $6.5 million net gain for the year ended December 31, 2013 consisted of a net gain of $6.1 million from the sale of oil and gas rights and a $1.5 million net gain resulting from $3.1 million of insurance proceeds received on equipment lost in mining activities with a carrying value of $1.6 million, offset in part by $1.1 million of net losses generated from the disposal of equipment in the normal course of business. The $8.0 million net gain for the year ended December 31, 2012 consisted of a net gain of $6.3 million from the sale of oil and gas rights and $1.7 million in net gains from the disposal of equipment and reclaimed land in the normal course of business. 
Net Income Attributable to Noncontrolling Interest 
Net income attributable to noncontrolling interest relates to the 49% ownership interest in Harrison Resources owned by a subsidiary of CONSOL through September 30, 2014. Net income attributable to noncontrolling interest was $1.2 million for the year ended December 31, 2013, an increase of $0.4 million from $0.8 million for the year ended December 31, 2012. This increase in net income attributable to noncontrolling interest was primarily due to lower operating costs at the Harrison mine. 
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 operation, replace reserves and fund capital expenditures, including costs of acquisitions from time to time, servicing of our debt and paying cash distributions to our unitholders when we are in a position to do so. Our primary sources of liquidity to meet these needs are cash generated by our operations and the limited remainder of our initial term loan borrowing under the 2014 Financing Agreement. Also, if we are able to sell the remaining excess Illinois Basin equipment, a large-capacity shovel and several smaller pieces of equipment, our liquidity will be enhanced. Additionally, we would consider offers for the remaining coal reserves and/or facilities related to our Illinois Basin operations, which could further enhance our liquidity.
Our ability to satisfy our working capital requirements, meet debt service obligations, and fund planned capital expenditures substantially depends upon our future operating performance, which may be affected by prevailing economic conditions in the coal industry. To the extent our future operating cash flow or access to financing sources and the costs thereof are materially different than expected, our future liquidity may be adversely affected. 
We have managed our liquidity for the year ended December 31, 2014, with $22.6 million of cash flows provided from operations and $11.5 million of cash flows used in financing activities. As of December 31, 2014, our available liquidity was $5.9 million, which consisted entirely of cash on hand. Due to refinancing our credit facility and the future royalties generated by the Kemmerer coal reserves, we believe that our cash from operations will provide sufficient liquidity for at least the next twelve months.

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WESTMORELAND RESOURCE PARTNERS, LP AND SUBSIDIARIES

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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.
 
Westmoreland
Resource
Partners, LP
 
 
Oxford Resource Partners, LP
 
(Successor)(1)
 
 
(Predecessor)
 
Period of
December 31,
2014
 
 
Period from
January 1,
2014
through
December 31,
2014
 
Year Ended December 31,
 
 
 
 
2013
 
2012
 
 
 
 
(in thousands)
Net cash provided by (used in):
 
 
 
 
 
 
 
 
Operating activities
$
(1,820
)
 
 
$
24,385

 
$
9,716

 
$
31,776

Investing activities

 
 
(8,253
)
 
(22,463
)
 
(8,059
)
Financing activities
7,741

 
 
(19,221
)
 
11,859

 
(22,772
)
(1) See Note 3: Acquisition and Pushdown Accounting included in the notes to the consolidated financial statements included in “Item 8 - Financial Statements and Supplementary Data.”
Period of December 31, 2014 (Successor)
Net cash used in operating activities was $1.8 million for the period of December 31, 2014 which comprised of net loss of $4.4 million that comprised of $2.8 million in restructuring charges and $1.6 million in loss on the extinguishment of debt offset in part by a $1.8 million change in working capital.
Net cash provided by financing activities of $7.7 million for the period of December 31, 2014, resulted from the refinanced our credit facility with a $175.0 million credit facility. Proceeds of the new credit facility were used to retire our then existing first and second lien credit facilities totaling $158.8 million and to pay $8.4 million fees and expenses related to our new credit facility
Period from January 1, 2014 through December 31, 2014 Compared to Year Ended December 31, 2013 (Predecessor)  
Net cash provided by operating activities was $24.4 million for the year ended December 31, 2014 compared to $9.7 million of net cash provided in operating activities for the year ended December 31, 2013, an increase of $14.7 million. We experienced a net loss for the year ended December 31, 2014 of $24.2 million, an increase of $0.5 million compared to a net loss for the year ended December 31, 2013 of $23.7 million. The increase in the net loss was attributable in part to the WCC transactions which generated $8.2 million in nonrecurring costs. The $8.2 million in transaction-related costs comprised of $5.5 million in recapitalization costs and $2.8 million in share-based compensation expense which was triggered by change of control provisions for the LTIP. The $8.2 million in transaction expenses was offset in part by the receipt of $17.5 million in net legal settlement proceeds, a $8.7 million decrease in depreciation, depletion and amortization expense and a $1.7 million decrease in restructuring and impairment charges, respectively. These differences, combined with a $10.4 million favorable change in working capital, are the primary drivers of the increase in net cash provided by operating activities. The favorable change in working capital was primarily attributable to favorable changes of $9.4 million in accounts receivable, and $3.9 million in reclamation and mine closure costs, partially offset by an unfavorable change in accounts payable and accrued expenses of $2.0 million.
Net cash used in investing activities was $8.3 million for the year ended December 31, 2014 compared to $22.5 million for the year ended December 31, 2013, a decrease of $14.2 million. The $14.2 million decrease was attributable to a $14.0 million decrease in the cash used for restricted investments and bond collateral and a $6.4 million decrease in property, plant and equipment spend, partially offset by a $3.2 million reduction in net proceeds from the sale of assets and a $3.0 million reduction in insurance proceeds received.
Net cash used in financing activities was $19.2 million for the year ended December 31, 2014, a decrease of $31.1 million from net cash provided from financing activities of $11.9 million for the year ended December 31, 2013. The $31.1 million decrease in net cash used in financing activities was primarily attributable to the $12.6 million principal prepayment

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paid in conjunction with the receipt of $19.5 million in litigation settlement proceeds from a former customer compensating us for lost profits on coal sales due to a wrongful termination of a coal supply agreement and the $3.6 million redemption payment for the noncontrolling interest in Harrison.
Year Ended December 31, 2013 Compared to Year Ended December 31, 2012 (Predecessor) 
Net cash provided by operating activities was $9.7 million for the year ended December 31, 2013 compared to $31.8 million for the year ended December 31, 2012, a decrease of $22.1 million. We experienced a net loss for the year ended December 31, 2013 of $23.7 million, a decrease of $2.4 million compared to a net loss for the year ended December 31, 2012 of $26.1 million. The decrease in the net loss was attributable in part to a $13.9 million decrease in impairment and restructuring expenses related to our Illinois Basin operations and a $3.1 million decrease in depreciation, depletion and amortization, partially offset by $4.1 million in non-cash interest expense, a $3.3 million change in the fair value of warrants associated with the refinancing of our credit facility, $3.1 million of expenses related to our debt refinancing, a $1.3 million decrease in the net gain on sale of assets, and a $1.0 million increase in amortization and write-off of deferred financing costs. These differences, combined with $13.2 million in unfavorable changes in working capital, are the primary drivers of the decrease in net cash provided by operating activities. The unfavorable change in working capital was primarily attributable to a $14.7 million unfavorable change in accounts receivable resulting from expedited collections effort for the fiscal year ended December 31, 2012 which were not repeated for the fiscal year ended December 31, 2013.
Net cash used in investing activities was $22.5 million for the year ended December 31, 2013 compared to $8.1 million for the year ended December 31, 2012, an increase of $14.4 million. The increase was attributed to an $11.4 million increase in changes in restricted investments and bond collateral and a $6.0 million reduction in proceeds from the sale of assets, partially offset by a $2.6 million increase in insurance proceeds and a favorable change of $0.4 million in the purchase of property and equipment.
Net cash provided by financing activities was $11.9 million for the year ended December 31, 2013, up $34.6 million from net cash used in financing activities of $22.8 million for the year ended December 31, 2012. In the year ended December 31, 2012, we made $22.8 million of distributions to our unitholders. In the year ended December 31, 2013, we did not make any distributions to our unitholders and refinanced our credit facility which increased our debt by $20.3 million. Of this amount, $8.5 million was used to pay fees related to the refinancing.
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, the remainder of the initial term loan borrowings under the 2014 Financing Agreement, and proceeds from asset sales. 
The following table summarizes our capital expenditures by type for the years ended December 31, 2014 and 2013.
 
Westmoreland Resource Partners, LP
 
 
Oxford Resource Partners, LP
 
(Successor)
 
 
(Predecessor)
 
Period of
December 31,
2014
 
 
Period from
January 1, 2014
through
December 31,
2014
 
Year Ended December 31, 2013
 
 
 
 
 
 
 
 
(in thousands)
Coal reserves
33,152

 
 
$
5

 
$
1,532

Mine development

 
 
2,431

 
3,027

Equipment and components

 
 
13,502

 
15,738

Total
33,152

 
 
$
15,938

 
$
20,297



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Contractual Obligations 
We have contractual obligations that are required to be settled in cash. The amounts of our contractual obligations as of December 31, 2014 were as follows.
 
 
Westmoreland Resource Partners, LP (Successor)
 
 
Payment Due by Period
 
 
Total
 
Less than 1 Year
 
1 - 3 Years
 
4 - 5 Years
 
More than 5 Years
 
 
(in thousands)
Long-term debt obligations
 
$
175,000

 
$

 
$

 
$
175,000

 
$

Future interest obligations - long-term debt (1)
 
90,746

 
21,679

 
45,353

 
23,714

 

Capital lease obligation
 
35

 
6

 
29

 

 

Fixed-price diesel fuel purchase contracts
 
38,235

 
38,235

 

 

 

Asset retirement obligations
 
38,535

 
6,562

 
11,752

 
12,186

 
8,035

Operating lease obligations
 
9,146

 
5,886

 
3,260

 

 

Total
 
$
351,697

 
$
72,368

 
$
60,394

 
$
210,900

 
$
8,035

(1)
Interest on variable rate long-term debt was calculated using rates estimated by us at December 31, 2014 for the remaining term of outstanding borrowings.
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 ARO, and contractual performance. Historically, we secured these obligations with surety bonds supported by letters of credit. Subsequent to our 2013 refinancing, we have supported our surety bonds with cash deposits.
As of December 31, 2014, we had $34.6 million of surety bonds outstanding to secure certain reclamation obligations. Additionally, as of December 31, 2014, we had $9.1 million of cash deposits in support of these bonds. Further, as of December 31, 2014, we had $0.5 million of road bonds and $2.9 million of performance bonds outstanding that required no security. We believe these bonds and letters of credit will expire without any claims or payments thereon, and accordingly we do not expect any material adverse effect on our financial condition, results of operations or cash flows therefrom.
Critical Accounting Policies and Estimates 
Basis of Presentation and Principles of Consolidation
The accompanying consolidated financial statements include the accounts and operations of the Partnership and its consolidated subsidiaries and are prepared in conformity with accounting principles generally accepted in the United States of America (“US GAAP”). WCC's cost of acquiring our GP has been pushed-down to establish a new accounting basis for us beginning in the last minuted of December 31, 2014. Accordingly, the accompanying consolidated financial statements are presented for two period, Predecessor and Successor, which relate to the accounting periods preceding and succeeding the completion of the transaction. The Predecessor and Successor periods have been separated by a vertical line on the face of the consolidated financial statements to highlight the facts that the financial information for such periods has been prepared under two-different historical-cost bases of accounting.
Use of Estimates 
The preparation of financial statements in conformity with generally accepted accounting principles requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosures of contingent assets and liabilities at the date of the financial statements and reported amounts of revenues and expenses during the reporting period. Actual results could differ from those estimates.

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We have provided a summary of all significant accounting policies in Note 2, Summary of Significant Accounting Policies, to the audited consolidated financial statements presented elsewhere in this Annual Report on Form 10-K.  The most significant policies requiring the use of management estimates and assumptions relate to the collectability of accounts receivable, useful lives of fixed assets, valuation of coal reserves, reserve estimates of coal reserves, evaluations of asset impairment, recoverability of advanced royalties, useful lives of intangible assets, fair value of assets and liabilities under purchase accounting, and estimates of future asset retirement obligations. We believe that these significant policies involve a high degree of judgment and/or complexity.
Purchase and Pushdown Accounting
WCC's acquisition of our GP was accounted for using the acquisition method under ASC 805, Business Combination. Under the acquisition method, the purchase price was allocated to the underlying tangible and intangible assets acquired and liabilities assumed based on their respective fair values. The allocation of the purchase price is preliminary pending the completion of various analyses and the finalization of estimates. During the measurement period (which is not to exceed one year from the acquisition date), additional assets or liabilities may be recognized if new information is obtained about facts and circumstances that existed as of the acquisition date that, if known, would have resulted in the recognition of those assets or liabilities as of that date. The preliminary allocation may be adjusted after obtaining additional information regarding, among other things, asset valuations, liabilities assumed and revisions of previous estimates. These adjustments may be significant and will be accounted for retrospectively.
Per ASC 805-50-25-4 (effective November 18, 2014), we, as an acquiree of WCC through our GP, have the option to apply pushdown accounting in our consolidated financial statements when an acquirer (WCC) obtained control of us. We have chosen adopt pushdown accounting and will reflect purchase accounting adjustments in our consolidated financial statement.
Allowance for Doubtful Accounts 
We establish an allowance for losses on accounts receivable when it is probable that all or part of an outstanding balance will not be collected.  Our management regularly reviews the probability that a receivable will be collected and establishes or adjusts the allowance as necessary. 
Inventory 
Inventories, which include materials and supplies as well as raw coal, are stated at the lower of cost or market. Cost is determined using the average cost method. Coal inventory costs include labor, supplies, equipment, operating overhead and other related costs. 
Property, Plant and Equipment 
Property, plant and equipment are recorded at cost. Expenditures that extend the useful lives of existing plant and equipment or increase productivity of the assets are capitalized. Maintenance and repair costs that do not extend the useful life or increase productivity of the asset are expensed as incurred. Coal reserves are recorded at cost, or at fair value originally in the case of acquired businesses and application of pushdown accounting.
Coal reserves, mineral rights and mine development costs are depleted based upon estimated recoverable proven and probable reserves. Plant and equipment are depreciated on a straight-line basis over the assets’ estimated useful lives.
We assess the carrying value of our property, plant and equipment for impairment whenever events or changes in circumstances indicate that the carrying amount of an asset may not be recoverable. Recoverability is measured by comparing estimated undiscounted cash flows expected to be generated from such assets to their net book value. If net book value exceeds estimated cash flows, the asset is written down to fair value. When an asset is retired or sold, its cost and related accumulated depreciation and depletion are removed from the accounts. The difference between the net book value of the asset and proceeds on disposition is recorded as a gain or loss. Fully depreciated plant and equipment still in use are not eliminated from the accounts. Amortization of capital leases is included in depreciation, depletion and amortization

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Advanced Coal Royalties 
A substantial portion of our reserves are leased. Advanced coal royalties are advance payments made to lessors under terms of lease agreements that are typically recoupable through an offset or credit against royalties payable on future production. We write-off advanced coal royalties when recoverability is no longer probable based on future mining plans.
Intangible Assets 
Identifiable intangible assets acquired in a business combination must be recognized and reported separately from goodwill. In August 2007 we recorded intangible assets associated with certain customer relationships at fair value.  These balances arose from the purchase accounting for our acquisition of Oxford Mining and its subsidiaries and were amortized over their expected useful lives until December 31, 2014.
In December 2014, in conjunction with the WCC transactions, we have identified a favorable terminal lease at the Bellaire dock resulting from more favorable market prices than contracted prices in lease agreements as measured during a business combination. These intangible assets are amortized on a straight-line basis over the respective periods of the lease agreements.
Asset Retirement Obligations
Our asset retirement obligations, or ARO, primarily consists of estimated costs to reclaim surface land and support facilities at our mines and in accordance with federal and state reclamation laws as established by each mining permit.
We estimate ARO for final reclamation and mine closure based upon detailed engineering calculations of the amount and timing of the future costs for a third party to perform the required work. These estimates are based on projected pit configurations at the end of mining and are escalated for inflation, and then discounted at a credit adjusted risk-free rate. We record mineral rights associated with the initial recorded liability. Mineral rights are amortized based on the units of production method over the estimated recoverable, proven and probable reserves at the related mine, and the ARO is accreted to the projected settlement date. Changes in estimates could occur due to revisions of mine plans, changes in estimated costs, and changes in timing of the performance of reclamation activities. See Note 10. 
Warrants
In connection with our refinancing in June 2013, certain of the second lien lenders and lender affiliates received warrants entitling them to purchase common and subordinated units under a freestanding contract. The subordinated warrants were canceled on December 31, 2014. Pursuant to Financial Accounting Standards Board's Accounting Standards Board's Codification Topic 470-20, “Debt With Conversion and Other Options” (ASC 470-20), freestanding contracts that are settled in a company’s own stock, including common and subordinated unit warrants, are to be designated as an asset, liability or equity instrument. Both the common and subordinated unit warrants were determined to be liabilities and were recorded at fair value as determined using the Black-Scholes Pricing Model. ASC 470-20 further requires that the warrants' fair value be remeasured each reporting period, with the change in fair value being reported in the consolidated statements of operations. Fair value determinations prepared using the Black-Scholes Pricing Model require assumptions related to interest rates, unit price, exercise price, term and volatilities. 
Revenue Recognition
Revenue from coal sales is recognized at the time title and risk of loss passes to the customer in accordance with the terms of the underlying sales agreements and after any contingent performance obligations have been satisfied. Coal sales prices are subject to premiums and reductions based on variations in coal quality delivered versus specifications in our coal supply contracts, but such adjustments are typically confirmed in a matter of days. Risk of loss typically transfers to the customer at the mine or dock, when the coal is loaded on the rail, barge, or truck.
Royalty revenue relates to coal reserves which we lease to a third party and oil and gas rights. For the years ended 2014, 2013 and 2012, we received royalties of $0.3 million, less than $0.1 million and $1.5 million, respectively.
Non-coal revenue consists primarily of clay and limestone sales, service fees, and other miscellaneous revenue. Clay and limestone sales relate to material we recover during the coal mining process and sell to third parties. Service fees are earned for operating a coal unloading facility, providing river barge loading services, and hauling ash. Periodically, we recognize miscellaneous revenue related to lost coal claims that result from granting third-party right-of-way access through

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small portions of various mine complexes. In 2014, we also received $19.5 million from a former customer to compensate us for lost profits on a wrongfully terminated contract.
Item 7A.Quantitative and Qualitative Disclosures About Market Risk
Market risk includes risks that arise from changes in interest rates, foreign currency exchange rates, commodity prices, equity prices and other market changes that affect market-sensitive instruments. We believe our principal market risks are commodity price risks and interest rate risks.
Commodity Price Risks
We manage our commodity price risks for coal sales through the use of supply contracts and the use of forward-purchase contracts.
Some of the products used in our mining activities, such as diesel fuel and explosives, are subject to price volatility. Through our suppliers, we utilize forward-purchase contracts to manage the exposure related to this volatility. Additionally, our expected diesel fuel needs are protected, in varying amounts, by diesel fuel escalation provisions contained in coal supply contracts with some of our customers, allowing for a change in the price per coal ton sold. Price changes typically lag the changes in diesel fuel costs by one quarter and are recorded in coal sales. A hypothetical increase of $0.30 per gallon for diesel fuel would have increased the net loss by $1.1 million for the year ended December 31, 2014, and a hypothetical increase of 10% in explosives prices would have increased the net loss by $2.2 million for the year ended December 31, 2014.
Interest Rate Risks 
For the balance of our indebtedness that is not subject to the interest rate swap arrangements, we have exposure to changes in interest rates on our indebtedness associated with our 2014 Financing Agreement. At December 31, 2014, the weighted average cash interest rate on our debt under the 2014 Financing Agreement was 9.25%. Based on our borrowings at the end of 2014, 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 $870 thousand.
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-33 of this Annual Report on Form 10-K and are incorporated herein by reference.
Item 9.Changes in and Disagreements With Accountant on Accounting and Financial Disclosure
None. 
Item 9A.Controls and Procedures
Conclusion Regarding the Effectiveness of Disclosure Controls and Procedures
As of December 31, 2014, management conducted an evaluation, under the supervision and with the participation of our chief executive officer (“CEO”) and chief financial officer (“CFO”), of the effectiveness of the design and operation of our disclosure controls and procedures, as such term is defined in Rule 13a-15(e) and 15d-15(e) of the Exchange Act. Based upon that evaluation, our CEO and CFO concluded that our disclosure controls and procedures were effective as of December 31, 2014 in ensuring that information required to be disclosed was recorded, processed, summarized and reported within the time periods specified in the SEC’s rules and forms, and to provide reasonable assurance that information required to be disclosed by us in such reports is accumulated and communicated to management, including our CEO and CFO, 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, as such term is defined in Rules 13a-15(f) and 15d-15(f) under the Exchange Act. Internal control over financial reporting refers to a process designed by, or under the supervision of, our principal executive and principal financial officers or persons

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performing similar functions, and effected by the board of directors, management and other personnel, 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, and includes those policies and procedures that:
pertain to the maintenance of records that in reasonable detail accurately and fairly reflect the transactions and dispositions of our assets;
provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and that our receipts and expenditures are being made only in accordance with authorizations of our management and our directors; and
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.
Management evaluated the effectiveness of our internal control over financial reporting as of December 31, 2014, using the framework set forth by the Committee of Sponsoring Organizations of the Treadway Commission (COSO) in their 2013 Internal Control-Integrated Framework.. Based upon management’s evaluation, our CEO and CFO concluded that our internal control over financial reporting was effective as of December 31, 2014.
Changes in Internal Control Over Financial Reporting
There have been no changes in our internal control over financial reporting (as defined in Rules 13a-15(f) and 15d-15(f) under the Exchange Act) during the quarter ended December 31, 2014 that have materially affected, or are reasonably likely to materially affect, our internal control over financial reporting. 
Item 9B.OTHER INFORMATION 
Special Distribution - 25% Unit Dividend
On January 16, 2015, we announced a “25% unit dividend” as a one-time special distribution (the “Special Distribution”) of common units. The Special Distribution was for an aggregate of 206,549 of our common units, representing an approximately 25% unit dividend payable to public unitholders on a pro rata basis. The Special Distribution was effected as part of the completion of the series of transactions involving WCC previously announced on January 2, 2015.
The record date for the Special Distribution was January 27, 2015 (the “Record Date”). The distribution of our common units occurred on or about January 30, 2015 (the “Distribution Date”). The transfer agent did not distribute any fractional common units or compensation in lieu thereof. Each fractional common unit was rounded to the nearest whole common unit (and a 0.5 common unit was rounded to the next higher common unit).
Holders of our common units on the Record Date were not required to take any action in order to receive the Special Distribution. Common unitholders entitled to receive units in connection with the Special Distribution either received a book-entry account statement reflecting their ownership of the common units distributed to them in the Special Distribution or their brokerage accounts were credited for the common units distributed to them in the Special Distribution.


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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, Westmoreland Resources GP, LLC. Our general partner was not elected and is not subject to election in the future by our unitholders. Our general partner has a board of directors, and our unitholders are not entitled to elect the directors or 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.
During 2014, our general partner’s board of directors had seven directors, three of whom were independent as defined under the independence standards established by the NYSE and the Exchange Act. Our general partner’s board of directors had affirmatively determined that Peter B. Lilly, Robert J. Messey and Gerald A. Tywoniuk were independent as described in the rules of the NYSE and the Exchange Act.
Currently, our general partner’s board of directors has eight directors, four 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 Robert T. Clutterbuck, Keith D. Horton, Kurt D. Kost 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.

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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 of directors of our general partner. The following table shows certain information for the directors and executive officers of our general partner from January 1, 2014 to December 31, 2014, as well as certain information on directors and named executive officers from January 1, 2015 to the present.
Name*
 
Age
 
Position
Keith E. Alessi(e)
 
60
 
Chairman of the Board
George E. McCown(a)
 
79
 
Chairman of the Board
Keith E. Alessi(c)
 
60
 
President and Chief Executive Officer
Charles C. Ungurean(a)
 
65
 
President and Chief Executive Officer
Kevin A. Paprzycki(c)
 
44
 
Chief Financial Officer and Treasurer
Bradley W. Harris(a)
 
55
 
Senior Vice President, Chief Financial Officer and Treasurer
Jennifer S. Grafton(c)
 
38
 
Chief Legal Officer and Secretary(g)
Daniel M. Maher(a)
 
69
 
Senior Vice President, Chief Legal Officer and Secretary
Joseph E. Micheletti(f)
 
49
 
Executive Vice President
Gregory J. Honish(b)
 
58
 
Senior Vice President, Operations
Michael B. Gardner(g)
 
59
 
General Counsel
Michael B. Gardner(a)
 
59
 
Vice President-Legal, General Counsel-Regulatory/Environmental and Assistant Secretary
Denise M. Maksimoski(b)
 
40
 
Senior Director, Accounting
Brian D. Barlow(a)
 
44
 
Director
Matthew P. Carbone(a)
 
48
 
Director
Robert T. Clutterbuck(d) 
 
64
 
Director
Jennifer S. Grafton(d)
 
38
 
Director
Keith D. Horton(d)
 
61
 
Director
Kurt D. Kost(d) 
 
58
 
Director
Peter B. Lilly(a)
 
66
 
Director
Robert J. Messey(a)
 
69
 
Director
Kevin A. Paprzycki(d)
 
44
 
Director
Gerald A. Tywoniuk(b)  
 
53
 
Director
Charles C. Ungurean(b)
 
65
 
Director
*For persons shown in italics, their positions terminated on December 31, 2014, in connection with the WCC transactions (February 25, 2015 in the case of Mr. Gardner).
(a) From January 1, 2014 to December 31, 2014.
(b) From January 1, 2014 to present.
(c) Effective January 1, 2015 to present
(d) Effective January 6, 2015 to present.

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(e) Effective January 13, 2015 to present
(f) Effective February 18, 2015 to present
(g) From January 1 - February 18, 2015
Keith E. Alessi was elected and has served as Chief Executive Officer and President of our general partner since January 1, 2015. He was elected and has served as a member of the board of directors since January 6, 2015, and was appointed Chairman of the Board of our general partner on January 13, 2015. Mr. Alessi has served in various capacities at WCC since 2007 and currently serves as its Chief Executive Officer. He was an adjunct lecturer at the University of Michigan Ross School of Business from 2001 to 2010 and was an Adjunct Professor at The Washington and Lee University Law School from 1999 to 2007. Mr. Alessi previously served as Chief Executive Officer, Chief Operating Officer or Chief Financial Officer of a number of public and private companies from 1982 to 2000. He currently serves as a member of the board of directors of MWI Veterinary Supply, Inc. Mr. Alessi’s experience at WCC with the coal industry and as Chief Executive Officer of various companies provide him with the necessary skills to be a member of the board of directors and chairman of both the board of directors and executive committee of our general partner. Mr. Alessi has a M.B.A. from the University of Michigan and a B.S. from Wayne State University and is a certified public accountant.
George E. McCown served as a member of the board of directors and Chairman of the Board of our general partner from 2007 through December 31, 2014. 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 middle-market companies in partnership with management, since he co-founded MDC in 1983. Mr. McCown received a M.B.A. from Harvard University and a B.S. in Mechanical Engineering from Stanford University.
Charles C. Ungurean served as President and Chief Executive Officer of our general partner from its formation in 2007 through December 31, 2014, and has served as a member of the board of directors of our general partner since its formation in 2007. In 1985, he co-founded our predecessor and wholly owned subsidiary, Oxford Mining Company. Mr. Ungurean served as President and Treasurer of our predecessor from 1985 to August 2007. He 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. His more than 40 years of experience in the coal industry, over 25 of which have been spent running our operations or the operations of our predecessor and wholly owned subsidiary, Oxford Mining Company, provide him with the necessary skills to be a member of the board of directors and a member of the executive committee of our general partner. Mr. Ungurean received a B.A. in General Studies from Ohio University and is a certified surface mine foreman in Ohio.
Kevin A. Paprzycki was elected and has served as Chief Financial Officer and Treasurer of our general partner since January 1, 2015. He was elected and has served as a member of the board of directors of our general partner since January 6, 2015. Mr. Paprzycki joined WCC as Controller and Principal Accounting Officer in June 2006 and was named Chief Financial Officer in April 2008. In June 2010, he was also named Treasurer. Prior to WCC, Mr. Paprzycki was Corporate Controller at Applied Films Corporation from 2005 to 2006. Mr. Paprzycki became a certified public accountant in 1994 and a certified financial manager and certified management accountant in 2004. His experience at WCC with the coal industry and as Chief Financial Officer provide him with the necessary skills to be a member of the board of directors and a member of the compensation committee of our general partner. Mr. Paprzycki earned his B.S. in Accountancy from Case Western Reserve University and his M.B.A from the University of Utah. 
Bradley W. Harris served as Senior Vice President, Chief Financial Officer and Treasurer of our general partner from October 2012 through December 31, 2014. Before joining us, he was Senior Vice President and Chief Financial Officer of Essar Resources, Inc., a subsidiary of Essar Global, Inc. that was formed to be the parent company for Trinity Coal Corporation (a Central Appalachia coal producer) and Essar Steel Minnesota Limited (a development stage iron ore producer), from July 2011 to December 2011. Prior to that, Mr. Harris was Senior Vice President, Chief Financial Officer and Treasurer of International Coal Group, Inc. (a Northern and Central Appalachia and Illinois Basin coal producer) from September 2006 to June 2011. He earned a M.B.A. and a B.S. in Accounting from Lehigh University and is a certified public accountant.
Jennifer S. Grafton was elected and has served as Chief Legal Officer of our general partner since January 1, 2015, and Secretary from January 1 until February 18, 2015. She was elected and has served as a member of the board of directors of our general partner since January 6, 2015. Ms. Grafton joined WCC as Associate General Counsel in December 2008, was named General Counsel and Secretary in February 2011 and was promoted to Senior Vice President, Chief Administrative Officer and Secretary in November 2014. Prior to WCC, Ms. Grafton worked in the corporate group of various Denver-based

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and national law firms focusing her practice on securities and corporate governance. She is a member of the Colorado bar. Ms. Grafton’s experience at WCC with the coal industry as Associate General Counsel, General Counsel and then Senior Vice President and Chief Administrative Officer provide her with the necessary skills to be a member of the board of directors and a member of the compensation committee of our general partner. Ms. Grafton graduated from the University of Michigan Ross School of Business with her M.B.A. with High Distinction, graduated from the University of Denver Sturm College of Law with her J.D., Order of St. Ives, and received her B.S. from the University of Puget Sound.
Daniel M. Maher served as Senior Vice President and Chief Legal Officer of our general partner from August 2010, and Secretary of our general partner from December 2010, until December 31, 2014. He was a partner in the Columbus, Ohio office of the international law firm of Squire Patton Boggs (US) LLP from March 1988 to December 2010 and prior thereto he was an associate and then partner with a predecessor firm to Squire from June 1972. Mr. Maher 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.
Joseph E. Micheletti has served as Executive Vice President of our general partner since February 18, 2015. Mr. Micheletti joined WCC in 2001 and has held a series of positions since that time including President and General Manager of WCC’s Jewett Mine. In June 2011, Mr. Micheletti was named Senior Vice President - Coal Operations at WCC overseeing their domestic mines. Mr. Micheletti has worked in the production, maintenance, processing, and engineering disciplines of the mining industry for 24 years and sits as a Director of the Rocky Mountain Coal Mining Institute.
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 35-year professional career at mines in Northern Appalachia, Central Appalachia, the Illinois Basin and the Powder River Basin. He is a licensed professional engineer in Ohio and West Virginia and a certified surface mine foreman in Ohio and Wyoming. Mr. Honish received a B.S. in Mining Engineering from the University of Wisconsin.
Michael B. Gardner served as General Counsel of our general partner from January 1, 2015, until February 18, 2015. Before that, he served as Vice President-Legal and General Counsel-Regulatory/Environmental of our general partner from June 2011 through December 31, 2014, as Assistant Secretary of our general partner from December 2010 through December 31, 2014, and as General Counsel and Secretary of our general partner from September 2007 until December 2010. Prior to joining us, from June 2004 until May 2007, Mr. Gardner served as Associate General Counsel of Murray Energy Corporation, a privately owned coal mining company. He is a licensed attorney in Ohio with more than 30 years of experience in the coal industry and in environmental regulatory compliance. Mr. Gardner serves on the Boards of Directors of the Ohio Coal Association and the Kentucky Coal Association. He 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. Mr. Gardner is a member of the American Corporate Counsel Association, Northeast Ohio Chapter, and the Cleveland Metropolitan Bar Association. He received a J.D. from Case Western Reserve University, a M.B.A. from Ashland University and a B.S. in Environmental Biology from Ohio University.
Denise M. Maksimoski has served as Senior Director, Accounting of our general partner since December 2009, and Director, Financial Reporting and General Accounting from August 2008 to December 2009. However, she ceased to be the chief accounting officer of our general partner on December 31, 2014. Prior to joining us, from 1997 to 2008, Ms. Maksimoski was with Deloitte & Touche, LLP in Washington, D.C. and Columbus, Ohio, most recently as an Audit Senior Manager from August 2005 to August 2008. She earned a B.A. in Accounting, Actuarial Studies and Mathematics from Thiel College and is a certified public accountant.
Brian D. Barlow served as a member of the board of directors of our general partner from 2007 through December 31, 2014. He has been a Managing Director of AIM since December 2011, and prior thereto was a Principal with AIM from January 2007 until December 2011. Prior to joining AIM, from August 2004 to August 2006, Mr. Barlow was a Senior Securities Analyst for Scion Capital, a private investment partnership located in Cupertino, California. He received a M.B.A. from Columbia Business School and a B.A. in Construction Sciences from the University of Washington.
Matthew P. Carbone served as a member of the board of directors of our general partner from 2007 through December 31, 2014. He 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

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Group’s West Coast operations and worked in the investment banking divisions of Morgan Stanley, First Boston Corporation and Smith Barney. He received a M.B.A. from Harvard Business School and a B.A. in Neuroscience from Amherst College.
Robert T. Clutterbuck was elected and has served as a member of the board of directors of our general partner since January 6, 2015. He is the managing partner and portfolio manager at Clutterbuck Capital Management LLC. Prior thereto, Mr. Clutterbuck was Chairman of Key Capital Partners, which provided brokerage, capital markets, insurance, investment banking and asset management expertise to business and private clients nationwide. He was also Chief Executive Officer of McDonald Investments Inc. and was a Senior Executive Vice President of KeyCorp. In addition to serving on the McDonald Investments Board, Mr. Clutterbuck has served on numerous philanthropic boards as well as several advisory boards of financial institutions. His extensive financial experience provide him with the necessary skills to be a member of the board of directors, chairman of the compensation committee and a member of the audit committee of our general partner. With respect to the audit committee, Mr. Clutterbuck was designated as financially literate in accordance with NYSE listing standards based on his education and experience. He earned a bachelor’s degree from Ohio Wesleyan University and a M.B.A. from the University of Pennsylvania Wharton School of Business.
Keith D. Horton was elected and has served as a member of the board of directors of our general partner since January 6, 2015. On January 1, 2015 he retired from his position as President of PVR Coal, a subsidiary of Regency Gas Partners. From March 2010 until March 2014, Mr. Horton was Executive Vice President and Chief Operating Officer - Coal at PVR Partners, a publicly traded master limited partnership. He has an extensive background in coal operations and management, including a mine engineer position with WCC that was his first position out of college. Mr. Horton’s extensive experience in the coal industry provide him with the necessary skills to be a member of the board of directors, a member of the executive committee and a member of the audit committee of our general partner. With respect to the audit committee, Mr. Horton was designated as financially literate in accordance with NYSE listing standards based on his education and experience. He earned a bachelor’s degree in Engineering of Mines from West Virginia University and completed the University of Virginia Darden School of Business’ Executive Management Program.
Kurt D. Kost was elected and has served as a member of the board of directors of our general partner since January 6, 2015. He has over 34 years experience in the mining industry. Mr. Kost’s expertise includes coal operations and engineering; safety and process management related to operational and maintenance improvements; deploying technology in practical field applications; post-merger organization design and implementation; and executive management and leadership. From September of 2013 until May of 2014 he was a Senior Vice President with Norwest Corporation and from 2009 until 2012 was President of Alpha Natural Resources. Mr. Kost’s extensive experience in the coal industry provide him with the necessary skills to be a member of the board of directors and a member of the audit committee of our general partner. With respect to the audit committee, Mr. Kost was designated as financially literate in accordance with NYSE listing standards based on his education and experience. Mr. Kost earned a bachelor’s degree in Mining Engineering from South Dakota School of Mines and Technology and in 2004 completed Harvard Business School’s Advanced Management Program.
Peter B. Lilly served as a member of the board of directors of our general partner from June 2010 through December 31, 2014. Since February 2009, he has been a part-time consultant relating to the coal industry international market and has also focused on investments in commercial real estate as a member through and as a member of his company, Harm Group, LLC. Before that, Mr. Lilly was an executive officer with CONSOL from October 2002 until his retirement in January 2009. He is a former board member of the National Coal Association, the American Mining Congress and the World Coal Institute and a former chairman of the Safety Committee of the National Mining Association. Mr. Lilly earned a M.B.A. from Harvard Business School and a B.S. in General Engineering and Applied Science from the United States Military Academy at West Point.
Robert J. Messey served as a member of the board of directors of our general from October 2010 through December 31, 2014. He has been an independent management consultant since April 2008. Before that, Mr. Messey served as Senior Vice President and Chief Financial Officer of Arch Coal, Inc. from December 2000 until April 2008. He served as a member of the Audit Committee, qualifying as an “audit committee financial expert.” Mr. Messey earned a B.S. in Business Administration from Washington University.
Gerald A. Tywoniuk has served as a member of the board of directors of our general partner since January 2009. He also serves as a director and audit committee chairperson of the general partner of American Midstream Partners, LP, as well as a director and audit committee member of the general partner of Landmark Infrastructure Partners LP. In addition to his board of director roles, Mr. Tywoniuk has provided various interim and project Chief Financial Officer services since May 2010. From June 2008 until August 2013, he held various management and finance roles, including Plan Representative, acting Chief Executive Officer, and Chief Financial Officer of Pacific Energy Resources Ltd., an oil production company.

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Mr. Tywoniuk joined that company in June 2008 to help the management team work through the company’s financially distressed situation. The board of the company elected to file for Chapter 11 protection in March 2009. In December 2009, the company completed the sale of its assets, and by August 2013 the company completed its liquidation. Mr. Tywoniuk previously served as Chief Financial Officer of Pacific Energy Partners, LP, an oil and refined products pipeline and storage partnership from 2002 to 2006, and MarkWest Energy Partners, L.P. and its predecessor, principally a natural gas and liquids midstream services partnership, from 1997 to 2002. He has over 32 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 and a member and chairman of the audit committee of our general partner. With respect to the Audit Committee, Mr. Tywoniuk was designated as an audit committee financial expert and financially literate in accordance with NYSE listing standards based on his education and experience. He earned a Bachelor of Commerce degree from The University of Alberta, Canada, and is a Canadian chartered accountant.
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, Westmoreland Resource Partners, LP, 9450 South Maroon Circle, Suite 200, Englewood, Colorado 80112, or by emailing such request to Investor Relations at ir@oxfordresources.com. Amendments to, or waivers from, the code of business conduct and ethics will also be available on our website and reported as may be required under SEC rules; however, any technical, administrative or other non-substantive amendments to the code of business conduct and ethics may not be posted. Please note that the preceding Internet address is for information purposes only and is not intended to be a hyperlink. Accordingly, no information found or provided at that Internet address or at our website in general is intended or deemed to be incorporated by reference herein.
Conflicts Committee
Our partnership agreement provides for the conflicts committee (the “Conflicts Committee”), as circumstances warrant, to review conflicts of interest between us and our general partner or between us and affiliates of our general partner. The Conflicts Committee, consisting solely of independent directors, determines if the resolution of a conflict of interest that has been presented is fair and reasonable to us. The members of the Conflicts Committee may not be executive officers or employees of our general partner or directors, executive officers or employees of its affiliates. In addition, the members of the Conflicts Committee must meet the independence and experience standards established by the NYSE and the Exchange Act. The composition of our Audit Committee qualifies it to be, and our Audit Committee presently serves as, our Conflicts Committee.
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. Keith E. Alessi, Keith D. Horton and Charles C. Ungurean serve as the members of the Executive Committee. Mr. Alessi 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, Robert T. Clutterbuck, Keith D. Horton and Kurt D. Kost are our independent directors and serve as the members of the Audit Committee, and all have the requisite education and experience sufficient to be designated as financially literate under NYSE listing standards. The board has determined that Mr. Tywoniuk, who serves as the chairman of the Audit Committee, has the

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accounting or related financial management expertise sufficient to qualify 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 statement on auditing standards No. 16 (PCAOB Auditing Standard No. 16, Communications With Audit Committees, Related Amendments to PCAOB Standards and Transitional Amendments to AU Section 380), and makes recommendations to the board of directors of our general partner regarding the inclusion of our audited financial statements in this Annual Report on Form 10-K.
Compensation Committee
The board of directors of our general partner has established a compensation committee (the “Compensation Committee”). The Compensation Committee establishes standards and makes recommendations concerning the compensation of our directors. Robert T. Clutterbuck, Kevin A. Paprzycki and Jennifer S. Grafton serve as the members of the Compensation Committee. Mr. Clutterbuck 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.
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, Samuel Hagreen, at ir@oxfordresources.com, or at the following address: Name of the Director(s), c/o Secretary, Westmoreland Resource Partners, LP, 9450 South Maroon Circle, Suite 200, Englewood, Colorado 80112.
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, 2014, other than a late Form 3 filing made by WCC.
Item 11.    Executive Compensation
Compensation Discussion and Analysis
The following is a discussion of the compensation policies and decisions of the board of directors of our general partner (the “Board”) and the Compensation Committee for the year ended December 31, 2014 with respect to the following individuals, who were during all of 2014 executive officers of our general partner and are referred to as the “named executive officers”:
Charles C. Ungurean, President and Chief Executive Officer;
Bradley W. Harris, Senior Vice President, Chief Financial Officer and Treasurer;
Daniel M. Maher, Senior Vice President, Chief Legal Officer and Secretary;

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Gregory J. Honish, Senior Vice President, Operations; and
Michael B. Gardner, Vice President - Legal, General Counsel - Regulatory/Environmental and Assistant Secretary
Our compensation program has historically been 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 has generally been made up of the following components: (i) base salary, designed to compensate our executive officers for work performed during the fiscal year; (ii) short-term incentive programs, designed to reward our executive officers for our financial and safety performances and for their individual performances during the fiscal year; and (iii) equity-based awards granted under our LTIP, which were meant to align our executive officers’ interests with those of our unitholders and our long-term performance.
On December 31, 2014, our general partner was acquired by WCC. As a result, a number of our named executive officers were terminated on that date.
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 historically employed all of the employees that operate our business. These responsibilities historically included establishing and maintaining the policies and practices with respect to executive compensation. The Board appointed and maintained 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 have consisted 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 have been charged with, among other things, the responsibility of:
reviewing executive officer compensation policies and practices to ensure adherence to our compensation philosophies and that the total compensation paid to our executive officers is fair, reasonable and competitive;
reviewing base salary levels for our executive officers and determining any adjustments thereto;
assessing the individual performance of our executive officers and their contributions to our company-wide performance;
determining the annual bonuses to be provided to our executive officers for a given year after taking into account target bonus levels set forth in executive officers’ employment agreements or otherwise established for the year; and
determining the types, amounts and vesting terms of awards to be provided to our executive officers under our LTIP.
In making compensation determinations, the Compensation Committee and the Board have historically considered the recommendations of our Chief Executive Officer (and our Chief Legal Officer in the case of Mr. Gardner) 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 have been 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 has been to attract and retain individuals of demonstrated competence, experience and leadership who share our business aspirations, values, ethics and culture. A further objective has been to provide incentives to and reward our executive officers and other key employees for positive contributions to our business and operations, and to align their interests with our unitholders’ interests.
In setting our compensation programs, we considered 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;

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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 2014 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 January 2013, but relating to performance in the immediately preceding year, we made equity-based awards as a part of our annual compensation decision-making process. We did not do so for 2014, and no equity-based awards were made as a part of 2014 compensation.
Compensation decisions for individual executive officers were the result of the subjective analysis of a number of factors, including the individual executive officer’s experience, skills or tenure with us, changes to the individual executive officer’s position and responsibilities, and our performance. In measuring the contributions of executive officers and our performance, a variety of financial measures were considered, including non-GAAP financial measures used by management to assess our financial performance. For 2014, the Board established an EBITDA-based measure as the primary measure of our operating performance. In addition, our safety performance and an evaluation of the individual performance of each of the executive officers were considerations.
In making individual compensation decisions, the Compensation Committee and the Board relied 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 2014. 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.
For each of the 2013 and 2014 performance periods, our Compensation Committee made compensation recommendations to the Board based upon trends occurring within our industry, including from a peer group of companies that our Compensation Committee identified and reviewed on at least an annual basis. The peer group of companies utilized in both 2013 and 2014 consisted of Alliance Resource Partners, L.P., Alpha Natural Resources, Cloud Peak Energy, Hallador Energy Company, LRR Energy, LP, Natural Resource Partners, L.P., Patriot Coal Corporation, Rhino Resource Partners, L.P., and Walter Energy, Inc.

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Elements of the Compensation Programs
Overall, our executive officer compensation programs have been designed to be consistent with the philosophy and objectives set forth above. The principal elements of those executive officer compensation programs are summarized in the table below, followed by a more detailed discussion of each compensation element.
Element
 
Characteristics
 
Purpose
Base Salaries
 
Fixed annual cash compensation in the form of base salaries. Base salaries of comparable positions within our peer group of companies have been taken into account. Our executive officers have been eligible for periodic increases in base salary. Increases have been based on performance or such other factors as the Board or the Compensation Committee determined.
 
Keep our fixed annual compensation competitive with the market for skills and experience necessary to execute our business strategy.
 
 
 
 
 
Annual Incentive Bonuses
 
Performance-related annual cash incentives earned based on company objectives and individual performance of the executive officers. Trends for our peer group have been taken into account in setting annual cash incentive awards.
 
Align annual compensation with our financial and safety performances and reward our executive officers for individual performance during the year. Amounts provided as incentive bonuses have also been designed to provide competitive total direct cash compensation; potential for awards above or below target amounts have been 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 have been based on our performance and on competitive practices at peer companies. No awards have been made for 2014. Awards have been settled upon vesting with an issuance of common units.
 
Align interests of our executive officers with unitholders and motivate and reward our executive officers to increase unitholder value over the long term.
 
 
 
 
 
Retirement Plan
 
Discretionary qualified 401(k) retirement plan benefits have been available for our executive officers.
 
Provide our executive officers with the opportunity to save for their future retirement.
 
 
 
 
 
Health and Welfare Benefits
 
Health and welfare benefits (medical, dental, vision, disability insurance and life insurance) have been available for our executive officers.
 
Provide benefits to meet the health and wellness needs of our executive officers and their families.
Base Salaries
Design.  Base salaries for our executive officers have been 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 has also been 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 have sought to compensate executive officers for their performance throughout the year with annual base salaries that are fair and competitive within our marketplace and which ensure the attraction, development and retention of superior talent. We believe that executive officer base salaries should be competitive with salaries for executive officers in similar positions and with similar responsibilities in our marketplace, adjusted for financial and operating performance, and each executive officer’s personal performance, length of service with us and previous work experience. For 2014, base salary determinations

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focused on the above considerations and also were made based upon relevant market data, including data from our peer group.
Base salaries have been reviewed annually to ensure continuing consistency with market levels and our level of financial performance during the prior year. Adjustments to base salaries and salary ranges have reflected average movement in the competitive market as well as individual performance. Annual base salary adjustments, if any, for the Chief Executive Officer have been approved by the Non-employee Directors based upon recommendations from the Compensation Committee. Annual base salary adjustments, if any, for the other executive officers have been approved by the Board based upon recommendations from the Compensation Committee, which recommendations at times took into account input from the Chief Executive Officer (and the Chief Legal Officer in the case of Michael B. Gardner).
Actions Taken With Respect to Base Salaries.   Given the fact that the base salaries for a number of the executive officers had been unchanged for three or more years, the Compensation Committee and the Board gave serious consideration to and ultimately determined to make some increases in the base salaries for 2014. The Compensation Committee and the Board considered the salary levels of comparable executive officers in our peer group but the base salaries have not been benchmarked at any particular level relative to our peer group. The base salaries of certain of the executive officers for 2014 and 2015 are reflected in the table below.
Name
 
2014 Base Salary(1)
 
2015 Base Salary(2)
Charles C. Ungurean
 
$
500,000

 
$

Bradley W. Harris
 
315,000

 

Daniel M. Maher
 
296,500

 

Gregory J. Honish
 
220,500

 
220,500

Michael B. Gardner(3)
 
178,500

 
178,500

(1) The 2014 base salaries for the executive officers other than Messrs. Ungurean and Maher were increased by 5% over the base salaries for 2013. Mr. Ungurean elected not to seek and thus did not recommend or receive a 2014 base salary increase for himself, and the 2014 base salary for Mr. Maher was increased by 10% over his base salary for 2013.
(2) The employment of Messrs. Ungurean, Harris and Maher was terminated on December 31, 2014 in connection with the WCC transactions and accordingly they do not have any base salary for 2015.
(3) Mr. Gardner's employment terminated on February 25, 2015.
Bonuses
Annual Incentive Bonuses.  As one way of accomplishing compensation objectives, our executive officers have historically been rewarded for their contribution to our financial and operational success through the award of annual cash incentive bonuses. Annual incentive bonuses, if any, for the Chief Executive Officer have historically been approved by the Non-employee Directors based upon recommendations from the Compensation Committee. Annual incentive bonuses, if any, for the other executive officers have historically been approved by the Board based upon recommendations from the Compensation Committee, which recommendations may take into account input from the Chief Executive Officer (and the Chief Legal Officer in the case of Mr. Gardner).
For our executive officers, target amounts for the annual incentive bonuses have historically been set forth in their employment agreements. The employment agreements for the executive officers provide for their eligibility to receive annual incentive bonuses based on target amounts of a specified percentage of their annual base salaries, or such other greater percentage as may be approved by the Non-employee Directors (in the case of our CEO, Charles C. Ungurean) or the Board (in the case of our other executive officers), in any such case based on the recommendations of the Compensation Committee, which recommendations in the case of the other executive officers may take into account input from the CEO (and the Chief Legal Officer in the case of Mr. Gardner). The target bonus amounts, as a percentage of annual base salaries, were, for 2014, 125% for Mr. Ungurean, 100% for Messrs. Harris, Maher and Honish and 50% for Mr. Gardner.
The annual incentive bonus award for each executive officer has historically been contingent on the executive officer’s continued employment with our general partner at the time of the award. Annual incentive bonuses have historically been 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 have historically believed that this approach to assessing performance for annual incentive bonus purposes results in the most appropriate bonus

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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 2014:
the level of achievement of certain financial performance goals for the year (our budgeted Adjusted EBITDA less maintenance and mine development capital expenditures for the year), with a weighting as a percentage of the target bonus amounts at the target level for such factor of 50% (35% for Mr. Gardner) for 2014;
the level of achievement of established safety criteria for the year, with a weighting as a percentage of the target bonus amounts at the target level for such factor of 15% for 2014; and
the discretionary bonus amount determined based on personal performance criteria, with a weighting as a percentage of the target bonus amounts of 35% (50% for Mr. Gardner) for 2014.
In applying the first two, non-discretionary factors, there have historically been 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 have also been 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 have been considered to be the most appropriate measures upon which to base the annual incentive cash bonus decisions as the Compensation Committee and our Board believed 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 2014.
Name
Financial
Performance(1)
 
Safety(2)
 
Personal
Performance(3)
 
Total
Charles C. Ungurean(4)
$
184,135

 
$
110,480

 
$
184,135

 
$
478,750

Bradley W. Harris(5)
157,500

 
94,500

 
157,500

 
409,500

Daniel M. Maher(5)
148,500

 
89,100

 
148,500

 
386,100

Gregory J. Honish(5)
110,250

 
66,150

 
110,250

 
286,650

Michael B. Gardner(6)
31,238

 
13,387

 
44,625

 
89,250

 
(1) 
The portion of the bonus for the Company’s financial performance was paid at 100% of the target level (subject to the adjustment for Mr. Ungurean described in Footnote (4)) without reference to EBITDA itself and instead was awarded for achievement of the $19.5 million settlement in the Big Rivers litigation and the closing of the WCC transactions.
(2) 
Safety is considered of paramount importance to the Company, and the Company is very pleased with the strong safety performance for 2014. This performance saw achievement well in excess of the target level of achievement for the safety component, resulting in an award at 200% of the target level (subject to the adjustment for Mr. Ungurean described in Footnote (4) and except that the award was at 100% of the target level for Mr. Gardner).
(3) 
All of the executive officers other than Mr. Gardner were further rewarded for personal performance above their target levels for achievement of the $19.5 million settlement in the Big Rivers litigation and closing of the WCC transactions (subject to the adjustment for Mr. Ungurean described in Footnote (4)). Mr. Gardner received an award for personal performance at his target level.
(4) 
Mr. Ungurean was entitled to a total bonus of $812,500, and voluntarily agreed to a reduction in that bonus of $333,750. That reduction has been reflected in the various bonus components on a pro rata basis. With this reduction, the annual incentive bonus award for Mr. Ungurean represented 95.8% of his base salary and 76.6% of his target bonus amount.
(5) 
The annual incentive bonus awards for each of Messrs. Harris, Maher and Honish represented 130% of his base salary and also 130% of his target bonus amount.
(6) 
The annual incentive bonus award for Mr. Gardner represented 50% of his base salary and 100% of his target bonus amount.

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Retention Bonuses.  Each of Messrs. Harris, Maher and Honish were eligible for retention bonuses payable if he remained in employment through December 31, 2014 or if there was an earlier change in control transaction. All of them remained in employment through December 31, 2014, and there was also a change in control transaction that occurred on that date. As a consequence, retention bonuses were paid to Messrs. Harris, Maher and Honish in 2014 in the amounts set forth in the table below. The purpose of the retention bonuses was to improve the chances of our general partner retaining the services of these executive officers, which retentions the Compensation Committee and the Board had determined to be important for us.
Name
 
2014
Retention
Bonus
Bradley W. Harris
 
$
200,000

Daniel M. Maher
 
180,000

Gregory J. Honish
 
140,000

  
Total Bonuses for 2014.  Including the annual cash incentive bonuses and the retention bonuses for 2014 described in the tables above, our executive officers received total bonuses for 2014 in the amounts set forth in the table below.
Name
 
Incentive Bonus
 
Retention Bonus
 
Total Bonus
Charles C. Ungurean
 
$
478,750

 
$

 
$
478,750

Bradley W. Harris
 
409,500

 
200,000

 
609,500

Daniel M. Maher
 
386,100

 
180,000

 
566,100

Gregory J. Honish
 
286,650

 
140,000

 
426,650

Michael B. Gardner
 
89,250

 

 
89,250

 
Total Severance Benefits for 2014.  The employment by our general partner of each of Messrs. Ungurean, Harris and Maher ended on December 31, 2014, and by reason thereof each of them was entitled to certain severance benefits in the amounts as set forth in the table below.
Name
 
Salary-Based Severance ($)(1)
 
Health Benefits Severance ($)(2)
 
Total Severance Benefits
Charles C. Ungurean
 
$
1,000,000

 
$
39,170

 
$
1,039,170

Bradley W. Harris
 
945,000

 
23,122

 
968,122

Daniel M. Maher
 
594,000

 
2,807

 
596,807

(1) 
The salary-based severance consists of two times annual salary ($500,000) for Mr. Ungurean, three times annual salary ($315,000) for Mr. Harris and two times annual salary ($296,500) for Mr. Maher.
(2) 
The health benefits severance is the value of two years of health benefits coverage for Mr. Ungurean and his family, 18 months of COBRA health benefits coverage for Mr. Harris and two months of health benefits coverage for Mr. Maher. 
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 was 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 were 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 can provide a vital link between the long-term results achieved for our unitholders and the rewards provided to executive officers and other key employees.
An amendment to our LTIP was adopted effective December 31, 2013, increasing the number of our common units authorized under our LTIP.

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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 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 2014, we have always issued common units in lieu of cash. Unvested phantom units were 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 vested 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 vested generally on the same basis as before and the remaining 50% of the phantom units vested based on and upon achievement of specified performance criteria. For Mr. Gardner, all of the phantom units awarded to him vested on the same basis as before. All LTIP awards for our executive officers vested in full upon a change in control of us or our general partner, which occurred on December 31, 2014 by reason of the closing of the WCC transactions.
Equity-Based Award Policies.  Prior to 2010, equity-based awards were granted by the Board and were limited to the grants at our formation in 2007 (or for executives who joined us after our formation, upon or in connection with their commencement of employment) and grants that were made in certain limited circumstances to reward individual service and performance. In early 2010, the Board delegated a portion of its duties and responsibilities under our LTIP to the Compensation Committee with the directive that equity-based awards were to be awarded more regularly as part of the ongoing total annual compensation package for executive officers, rather than only in such discrete circumstances. Annual equity compensation grants, if any, for the CEO were approved by the Non-employee Directors based upon recommendations from the Compensation Committee. Annual equity compensation grants for the other executive officers were approved by the Board based upon recommendations from the Compensation Committee, which recommendations may have taken into account input from the CEO (and the Chief Legal Officer in the case of Mr. Gardner).
Equity-Based Awards for 2014.  The Board determined not to and did not approve any awards of phantom units under the LTIP for our executive officers with respect to their 2014 performance.
Deferred Compensation 
Tax-deferred retirement plans are a common way that companies assist employees in preparing for retirement. We provide our eligible executive officers and other employees with an opportunity to participate in our 401(k) plan. The plan allows executive officers and other employees to contribute compensation for retirement up to Internal Revenue Service imposed limits, either on a tax deferred or after-tax basis. The 401(k) plan permits us to make annual discretionary contributions to the plan as a percentage of the eligible compensation of participants in the plan. Committed annual contributions of 3% or more of such eligible compensation will maintain “safe harbor” tax-qualified status for the plan. For 2014, we did not commit to make an employer discretionary contribution and no contribution is being made to the 401(k) plan. Decisions regarding this element of compensation have not impacted any other element of compensation. 
Perquisites and Other Benefits 
Although perquisites are not a significant factor in our compensation programs, we provided certain limited perquisite and personal benefits to certain of the named executive officers, including the use primarily for business purposes (with personal usage being limited to usage for commuting purposes) of a company-owned automobile for Mr. Ungurean. We provided these benefits to assist the executive officers in performing their services for us and they were 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 Company has reviewed and is anticipating legislative and regulatory developments with respect to such a policy and could adopt such a policy consistent with applicable legal and regulatory requirements and securities exchange listing standards, as well as economic and market conditions. 
Employment and Severance Arrangements 
We have considered the maintenance of a sound management team to be essential to protecting and enhancing our best interests. To that end, historically we recognized that the uncertainty that may exist among management with respect to

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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 historically had employment agreements with our executive officers. For each of our named executive officers, the current terms of these employment agreements ran through December 31, 2015 or later in the case of Mr. Ungurean. These employment agreements have provided for the base salary and target bonus amounts for each executive officer and contained severance arrangements that we believed were appropriate to encourage the continued attention and dedication of members of our management. The employment agreements with Messrs. Ungurean, Harris and Maher terminated with the termination of their employment on December 31, 2014, entitling them to severance benefits under their employment agreements. The employment agreement with Mr. Gardner terminated with the termination of his employment on February 25, 2015, entitling him to severance benefits under his employment agreement.
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, 2014 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
Robert T. Clutterbuck, Chairman
Kevin A. Paprzycki
Jennifer S. Grafton
Risk Assessment in Compensation Programs
Our Compensation Committee and our Board have analyzed the potential risks arising from our compensation policies and practices, and our Compensation Committee and our Board have determined that there are no such risks that are reasonably likely to have a material adverse effect on us.

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Summary Compensation Table
The following table sets forth certain information with respect to the compensation paid to the named executive officers for the periods indicated.
 
Name and Principal Position
Year
Salary ($)
Bonus ($)(1)
Severance
Benefits
($)(2)
Unit
Awards
($)(3)
All Other Compensation
($)(4)
Total ($)
Charles C. Ungurean
2014
$
501,923

$
478,750

$
1,039,170

$

$
3,863

$
2,023,706

President and Chief Executive Officer
2013
501,923

616,900


500,000

3,984

1,622,807

2012
511,155

275,000


526,688

13,835

1,326,678

Bradley W. Harris
2014
315,923

609,500

968,122


9,175

1,902,720

Senior Vice President, Chief Financial Officer and Treasurer
2013
301,154

396,100


300,002

8,960

1,006,216

2012
108,642

162,500


908,000

3,090

1,182,232

Daniel M. Maher
2014
297,624

566,100

596,807


9,349

1,469,880

Senior Vice President, Chief Legal Officer and Secretary
2013
271,039

390,250


270,000

9,269

940,558

2012
277,847

135,000


270,038

19,069

701,954

Gregory J. Honish
2014
221,146

426,650



283

648,079

Senior Vice President, Operations
2013
210,808

277,300


210,003

283

698,394

2012
220,040

102,500


210,054

10,083

542,677

Michael B. Gardner
2014
179,023

89,250



10,683

278,956

Vice President – Legal, General Counsel – Regulatory/Environmental and Assistant Secretary
2013
170,654

134,200


85,003

10,683

400,540

2012
186,144

68,000


82,545

17,683

354,372

(1) 
All of the 2014 bonus amounts for each named executive officer were paid in 2014, except that the incentive bonus amount for Mr. Gardner was and will be paid partly in December 2014 and the remainder in March 2015. The 2013 bonus amount for Mr. Maher included a remaining employment inducement bonus amount of $33,750 paid in early 2013.
(2) 
All of the severance benefits for 2014 accrued on December 31, 2014 and are payable within 60 days after that date except for the health severance benefits that are payable over the period of continued health care coverage (two years for Mr. Ungurean, 18 months for Mr. Harris and 2 months for Mr. Maher).
(3) 
No phantom units were awarded to the named executive officers for 2014. Except for Mr. Harris, 2012 amounts shown reflect the grant date fair value of phantom units awarded under the LTIP to each of them in January and March 2013 for each of the named executive officers except Mr. Gardner and in January 2013 only for Mr. Gardner, all relating to services provided in 2012. For Mr. Harris, 2012 amounts shown reflect the grant date fair value of phantom units awarded to him under the LTIP in connection with his employment in August 2012. For each named executive officer, the 2013 amount shown reflects the grant date fair value of phantom units awarded under the LTIP to each of them in January 2014 relating to services provided in 2013.
(4) 
For named executive officers, the 2014 amounts shown include payments made in 2014 with respect to life insurance benefits provided to each of the named executive officers, a holiday-related allowance paid in 2014 to each of the named executive officers, the taxable portion of automobile allowances paid to Messrs. Harris, Maher and Gardner, and the dues paid for Messrs. Ungurean, Harris and Maher for a dining and athletic club facility located in the same building as our executive offices.  Also for Mr. Ungurean, who is provided a company-owned automobile primarily for business use (with personal use being limited to usage for commuting purposes), the amount shown for 2014 includes the cost to us of providing the automobile to him for his use for the estimated personal usage portion thereof for commuting purposes (10% of the total cost) in the amount of $1,970.
Grants of Equity-Based Awards for 2014
There were no grants of equity-based awards to named executive officers for services during the year ended December 31, 2014.
Outstanding Equity-Based Awards at the End of 2014
All of the outstanding equity-based awards held by the named executive officers fully vested on December 31, 2014 in connection with the WCC transactions, and thus there were no outstanding equity-based awards held by the named executive officers at the end of 2014.  None of the named executive officers hold outstanding option awards.

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Units Vested in 2014
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 2014.  In the case of the phantom unit awards, all units and per unit values are adjusted for the 12-to-1 reverse split effective December 31, 2014. None of the named executive officers held or exercised any options in 2014.
Name
 
Number of Units Acquired on Vesting (#)
 
Value Realized on Vesting ($)
Charles C. Ungurean
 
47,216

(1) 
 
$
575,464

(1) 
President and Chief Executive Officer
 
 

 
 
 

 
Bradley W. Harris
 
30,148

(2) 
 
374,480

(2) 
Senior Vice President, Chief Financial Officer and Treasurer
 
 

 
 
 

 
Daniel M. Maher
 
25,694

(3) 
 
313,801

(3) 
Senior Vice President, Chief Legal Officer and Secretary
 
3.17202

(4) 
 
32,255

(4) 
Gregory J. Honish
 
19,857

(5) 
 
242,088

(5) 
Senior Vice President, Operations
 
 

 
 
 

 
Michael B. Gardner
 
7,752

(6) 
 
95,566

(6) 
Vice President-Legal, General Counsel-Regulatory/Environmental and Assistant Secretary
 
 
 

 
(1) 
Of these units, (i) 1,641 vested on March 31, 2014, with a value realized amount of $26,385 based on a unit value of $16.08 per unit, and (ii) 45,575 vested on December 31, 2014, with a value realized amount of $549,079 based on a unit value of $12.048 per unit.
(2) 
Of these units, (i) 2,790 vested on March 31, 2014, with a value realized amount of $44,870 based on a unit value of $16.08 per unit, and (ii) 27,358 vested on December 31, 2014, with a value realized amount of $329,610 based on a unit value of $12.048 per unit.
(3) 
Of these units, (i) 342 vested on January 1, 2014, with a value realized amount of $5,049 based on a unit value of $14.76 per unit, (ii) 824 vested on March 31, 2014, with a value realized amount of $13,242 based on a unit value of $16.08 per unit, and (iii) 24,528 vested on December 31, 2014, with a value realized amount of $295,509 based on a unit value of $12.048 per unit.
(4) 
Of these units, (i) 1.586010 vested on January 1, 2014, with a value realized amount of $2,469 which reflects an estimate of the fair value of such units as of such date, as determined in accordance with FASB ASC Topic 718, and (ii) 1.586009 vested on December 31, 2014, with a value realized amount of $29,786, which reflects the fair value of such units as of such date, as determined in accordance with FASB ASC Topic 718.
(5) 
Of these units, (i) 710 vested on March 31, 2014, with a value realized amount of $11,411 based on a unit value of $16.08 per unit, and (ii) 19,147 vested on December 31, 2014, with a value realized amount of $230,677 based on a unit value of $12.048 per unit.
(6) 
Of these units, (i) 539 vested on March 31, 2014, with a value realized amount of $8,660 based on a unit value of $16.08 per unit, and (ii) 7,213 vested on December 31, 2014, with a value realized amount of $86,906 based on a unit value of $12.048 per unit.
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, 2014.
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, 2014.
Potential Payment Upon Termination or Change in Control
Employment Agreements with Named Executive Officers
Our general partner had employment agreements with each of our named executive officers with terms through December 31, 2015 or later in the case of Mr. Ungurean. Messrs. Ungurean, Harris and Maher terminated their employment with our general partner on December 31, 2014, and have severance benefits under their terminated employment agreements as described above by reason thereof. The employment agreements for Messrs. Honish and Gardner remained in effect after December 31, 2014, although Mr. Gardner's employment and his employment agreement terminated on February 25, 2015.

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The discussion below relating to the employment agreements for named executive officers relate to these employment agreements for Messrs. Honish and Gardner which remained in effect after 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 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 (in the case of Mr. Honish) or one time (in the case of Mr. Gardner) the executive officer’s annual base salary on the date of such termination. 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 (in the case of Mr. Honish) or one time (in the case of Mr. Gardner) the executive officer’s base salary. The foregoing severance benefits are conditioned on the executive officer executing a release of claims in favor of our general partner and its affiliates including us. All of the severance benefits paid by our general partner are subject to reimbursement by us.
“Cause” is defined in each employment agreement as the executive officer having (i) engaged in gross negligence, gross incompetence or willful misconduct in the performance of the duties required of him under the employment agreement, (ii) refused without proper reason to perform the duties and responsibilities required of him under the employment agreement, (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 (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 (iii) a material breach by our general partner of any material provision of the employment agreement.
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. 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.
The following table shows the value of the severance benefits and other benefits for the named executive officers under such employment agreements as in effect on December 31, 2014, assuming each named executive officer had terminated employment on December 31, 2014.
Name
 
Payment Type
 
Termination
Without Cause
($)
 
Resignation for Good Reason
($)
Gregory J. Honish
 
Cash severance
 
441,000

 
441,000

Michael B. Gardner
 
Cash severance
 
178,500

 
178,500


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Compensation of Directors
Through 2014, our general partner’s non-employee directors were compensated for their service as directors under our general partner’s Non-Employee Director Compensation Plan, which was subsequently terminated effective January 1, 2015. Our non-employee directors for purposes of the plan were directors that (i) were not an officer or employee of our general partner or any of its subsidiaries or affiliates, (ii) were not affiliated with or related to any party that receives compensation from our general partner or any of its subsidiaries and affiliates, and (iii) had 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. Each non-employee director covered by the plan received an annual compensation package consisting of the following:
a cash retainer of $50,000;
an annual unit grant having a value of $50,000; and
where applicable, a committee chair retainer for each committee chaired of $10,000.
In addition, each non-employee director received the following per meeting fees:
per meeting fees for board meetings attended in person of $2,000; and
per meeting fees for telephonic board meetings and committee meetings of $500.
In addition, in 2014 our general partner’s non-employee directors were compensated for their service on the conflicts committee which was activated in connection with the WCC transactions.
Director Compensation Table for 2014
The following table sets forth the compensation paid to our non-employee directors for the year ended December 31, 2014, as described above.  In the case of the unit awards, all units and per unit values are adjusted for the 12-to-1 reverse split effective December 31, 2014. None of our non-employee directors held any unvested units as of December 31, 2014.
Name
 
Fees ($)(1)
 
Unit Awards
($)(2)
 
Total ($)
Gerald A. Tywoniuk
 
$
112,000

 
$
50,001

 
$
162,001

Peter B. Lilly
 
107,000

 
50,001

 
157,001

Robert J. Messey
 
96,500

 
50,001

 
146,501

(1) 
The amounts in this column represent the fees paid to the directors in 2014. These fees included $30,000 ($35,000 in the case of Mr. Tywoniuk who served as chairman) payable to each of the non-employee directors for service on the conflicts committee activated in connection with the WCC transactions.  All of the fees were paid in cash.
(2) 
The amounts in this column represent the value of unit awards made to directors under our LTIP in 2014. For each of the directors, (a) 778 units were granted and vested on March 31, 2014 and their market value is based on the closing price of $16.08 per unit on such date; (b) 1,241 units were granted and vested on June 30, 2014 and their market value is based on the closing price of $10.08 per unit on such date; (c) 1,303 units were granted and vested on September 30, 2014 and their market value is based on the closing price of $9.60 per unit on such date; and (d) 1,038 units were granted and vested on December 31, 2014 and their market value is based on the average closing price of $12.048 per unit for the five trading days ending two days prior to such date.
Compensation Committee Interlocks and Insider Participation
Brian D. Barlow, Peter B. Lilly, Gerald A. Tywoniuk and Robert J. Messey served as the members of the Compensation Committee through December 31, 2014. Mr. Barlow served 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.”

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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 3, 2015 (the “Ownership Reference Date”) by:
each person who is known to us to beneficially own 5% or more of such units to be outstanding;
our general partner;
each of the directors and named executive officers of our general partner; and
all of the directors and executive officers of our general partner as a group.
All information with respect to beneficial ownership has been furnished by the respective directors, officers or 5% or more unitholders as the case may be.
Our general partner is owned by WCC.
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 5,711,636 common units outstanding as of the Ownership Reference Date.
Name of Beneficial Owner
 
Common Units Beneficially Owned
 
Percentage of Common Units Beneficially Owned
Westmoreland Coal Company(1)
 
4,512,500

 
79.0
%
Keith E Alessi(1)
 

 
%
Kevin A. Paprzycki(1)
 

 
%
Jennifer S. Grafton(1)
 

 
%
Robert T. Clutterbuck(2)
 
32,584

 
*

Keith D. Horton(3)
 

 
%
Kurt D. Kost(4)
 

 
%
Gerald A. Tywoniuk(1)(5)
 
9,140

 
*

Charles C. Ungurean(6)(7)
 
56,956

 
*

Gregory J. Honish(6)
 
14,962

 
*

Joseph E. Micheletti(1)
 

 
%
All directors and executive officers as a group (consisting of 10 persons)
 
113,642

 
2.0
%
An asterisk indicates that the person or entity owns less than one percent.
(1) 
The address for this person or entity is 9450 South Maroon Circle, Suite 200, Englewood, Colorado 80112.
(2) 
The address for this person or entity is 10 Kensington Oval, Rocky River, Ohio 44116.
(3) 
The address for this person or entity is 391 Summer Sound Road, Piney Flats, Tennessee 37686.
(4) 
The address for this person or entity is 1112 Mountain Vista Drive, Bristol, Tennessee 37620.
(5) 
All of these common units are owned by a trust established and trusteed by Mr. Tywoniuk. Mr. Tywoniuk disclaims beneficial ownership of the units held by such trust, except to the extent of any pecuniary interest therein.
(6) 
The address for this person or entity is 544 Chestnut Street, Coshocton, Ohio 43812.

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(7) 
A total of 30,074 of these common units are owned by C&T Coal, Inc. Mr. Ungurean, as a shareholder of C&T Coal, Inc., shares voting and investment power with respect to the common units owned by C&T Coal, Inc. Mr. Ungurean disclaims beneficial ownership of the units, except to the extent of any pecuniary interest therein.
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 233,840 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 that remained available for future issuance under our LTIP as of December 31, 2014, as adjusted for the 12-to-1 reverse split effective December 31, 2014.
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 That Remained 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)
 

 
$

 
89,070

(2) 
Equity compensation plans not approved by security holders
 

 

 

 
Total
 

 
$

 
89,070

(2) 
(1) 
Our LTIP was approved by our partners (general and limited) prior to our initial public offering. As of December 31, 2014, our LTIP permitted the grant of awards covering an aggregate of 233,840 units, inclusive of prior award grants, which grants did not require approval by our limited partners.
(2) 
There are no phantom units outstanding under our LTIP as of December 31, 2014.


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Item 13.
Certain Relationships and Related Transactions, and Director Independence
At March 3, 2015, WCC owned 4,512,500 common units representing an 79.0% limited partner interest in us. WCC also owns all of the equity in and controls our general partner which owns a 0.6% general partner interest in us and all of our incentive distribution rights.
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 99.4% to the unitholders, including WCC as an affiliate of our general partner as the holder of an aggregate of 4,512,500 common units, and 0.6% 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 affiliate WCC would receive an annual distribution of approximately $18,818 on the 0.6% general partner interest and approximately $2,406,065 on the common 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 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
WCC owns 100.0% of our general partner. In addition to the 0.64% 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 $0.2000 per quarter. WCC also owns 79.0% of our outstanding equity interests.
Administrative and Operational Services Agreement
On August 24, 2007, we entered into an administrative and operational services agreement with Oxford Mining Company, LLC and our general partner. Under the agreement, our general partner provides services to us and is reimbursed for all related costs incurred on our behalf. The services that our general partner provides include, among other things, general administrative and management services, human resources, information technology, finance and accounting, corporate development, real property, marketing, engineering, operations (including mining operations), geologic services, risk management and insurance services. During 2014, we paid our general partner approximately $59.4 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.
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

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.


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. A copy of the code of business conduct and ethics is found at www.oxfordresources.com in the Investor Relations/Corporate Governance section. Additionally a unitholder may make such a request in writing by mailing such request to Investor Relations, Westmoreland Resource Partners, LP, 9540 South Maroon Circle, Suite 200, Englewood, CO 80112, or by emailing such request to Investor Relations at ir@oxfordresources.com.
Further information required for this item is provided in “Item 1. Business - Overview,” “Item 10. Directors, Executive Officers and Corporate Governance” and Note 20: Related Party Transactions included in the notes to the consolidated financial statements included in “Item 8 - Financial Statements and Supplementary Data.”

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Item 14.Principal Accountant Fees and Services 
The following table sets forth fees and out-of-pocket expenses billed by Grant Thornton LLP for the audit of our annual financial statements and other services rendered for the fiscal years ended December 31, 2014 and 2013:
 
 
For the Year Ended December 31,
Name
 
2014
 
2013
 
 
(in thousands)
Audit fees(1)
 
$
485

 
$
296

(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, services supporting the WCC transactions and services that are normally provided by the independent accountants in connection with statutory and regulatory filings or engagements, including reviews of documents filed with the SEC.
Pursuant to the charter of the Audit Committee, the Audit Committee is responsible for the oversight of our accounting, reporting and financial practices. The Audit Committee is responsible for the appointment, compensation, retention and oversight of the work of our external auditors; the preapproval 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 preapproval 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, and other services, must be preapproved 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.”
 

90


INDEX TO CONSOLIDATED FINANCIAL STATEMENTS 
 
Westmoreland Resource Partners, LP and Subsidiaries
 
Report of Independent Registered Public Accounting Firm
F-2
 
 
Consolidated Balance Sheets as of December 31, 2014 and 2013
F-3
 
 
Consolidated Statements of Operations for the period of December 31, 2014, the period of January 1, 2014 through December 31, 2014 and the years ended December 31, 2013 and 2012
F-5
 
 
Consolidated Statements of Partners’ Capital (Deficit) for the period of December 31, 2014, the period of January 1, 2014 through December 31, 2014 and the years ended December 31, 2013 and 2012
F-6
 
 
Consolidated Statements of Cash Flows for the period of December 31, 2014, the period of January 1, 2014 through December 31, 2014 and the years ended December 31, 2013 and 2012
F-7
 
 
Notes to Consolidated Financial Statements
F-9


F- 1



REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
Board of Directors and Unitholders of
Westmoreland Resource Partners, LP
We have audited the accompanying consolidated balance sheets of Westmoreland Resource Partners, LP (a Delaware limited partnership) and subsidiaries (the “Partnership”) as of December 31, 2014 (Successor) and Oxford Resource Partners, LP as of December 31, 2013 (Predecessor), and the related consolidated statements operations, partners’ capital (deficit) and cash flows for the period of December 31, 2014 (Successor) and the period from January 1, 2014 through December 31, 2014 and the two years in the period ended December 31, 2013 (Predecessor). These financial statements are the responsibility of the Partnership’s management. Our responsibility is to express an opinion on these financial statements based on our audits.
We conducted our audits in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. We were not engaged to perform an audit of the Partnership’s internal control over financial reporting. Our audits included consideration of internal control over financial reporting as a basis for designing audit procedures that are appropriate in the circumstances, but not for the purpose of expressing an opinion on the effectiveness of the Partnership’s internal control over financial reporting. Accordingly, we express no such opinion. An audit also includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements, assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.
In our opinion, the consolidated financial statements referred to above present fairly, in all material respects, the financial position of Westmoreland Resource Partners, LP and subsidiaries as of December 31, 2014 (Successor) and December 31, 2013 (Predecessor), and the results of their operations and their cash flows for the period of December 31, 2014 (Successor) and the period from January 1, 2014 through December 31, 2014 and the two years in the period ended December 31, 2013 (Predecessor) in conformity with accounting principles generally accepted in the United States of America.
/s/ GRANT THORNTON LLP
Cleveland, Ohio
March 6, 2015

F- 2



WESTMORELAND RESOURCE PARTNERS, LP AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEETS
(in thousands, except for unit data)
 
Westmoreland Resource Partners, LP
 
 
Oxford Resource Partners, LP
 
(Successor)
 
 
(Predecessor)
 
December 31,
 
 
December 31,
 
2014
 
 
2013
Assets
 
 
 
 
Current assets:
 
 
 
 
Cash
$
5,921

 
 
$
3,089

Receivables:
 
 
 
 
Trade
22,710

 
 
25,850

Other
116

 
 
4

 
22,826

 
 
25,854

Inventory
14,013

 
 
13,840

Other current assets
1,317

 
 
1,733

Total current assets
44,077

 
 
44,516

Property, plant and equipment:
 
 
 
 
Land and mineral rights
71,715

 
 
110,667

Plant and equipment
134,029

 
 
210,886

 
205,744

 
 
321,553

Less accumulated depreciation, depletion and amortization

 
 
(177,127
)
Net property, plant and equipment
205,744

 
 
144,426

Advanced coal royalties
9,153

 
 
11,404

Restricted investments and bond collateral
10,621

 
 
15,177

Intangible assets, net of accumulated amortization of $0 and $2.1 million in December 31, 2014 and 2013, respectively
31,000

 
 
1,188

Deferred financing costs, net
6,993

 
 
7,644

Total Assets
$
307,588

 
 
$
224,355

 
See accompanying notes to consolidated financial statements.

F- 3



 WESTMORELAND RESOURCE PARTNERS, LP AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEETS
(in thousands, except unit data)
 
Westmoreland Resource Partners, LP
 
 
Oxford Resource Partners, LP
 
(Successor)
 
 
(Predecessor)
 
December 31,
 
 
December 31,
 
2014
 
 
2013
Liabilities and Partners' Capital (Deficit)
 
 
 
 
Current liabilities:
 
 
 
 
Current installments of long-term debt
$
6

 
 
$
7,901

Accounts payable and accrued expenses:
 
 
 
 
Trade
19,135

 
 
23,932

Production taxes
1,033

 
 
1,293

Accrued compensation
1,531

 
 
3,389

Asset retirement obligations
7,783

 
 
5,996

Other current liabilities
4,007

 
 
3,457

Total current liabilities
33,495

 
 
45,968

Long-term debt, less current installments
175,029

 
 
155,375

Deferred revenue

 
 
3,578

Asset retirement obligations, less current portion
23,902

 
 
25,658

Warrants
1,981

 
 
4,599

Other liabilities
160

 
 
175

Total liabilities
234,567

 
 
235,353

Partners' capital (deficit):
 
 
 
 
Limited partners (5,505,087 and 1,740,589 units outstanding as of December 31, 2014 and 2013, respectively)
39,549

 
 
(13,460
)
General partner (35,291 units outstanding as of December 31, 2014 and 2013)
33,472

 
 
(2,507
)
Total Westmoreland Resource Partners, LP capital (deficit)
73,021

 
 
(15,967
)
Noncontrolling interest

 
 
4,969

Total partners’ capital (deficit)
73,021

 
 
(10,998
)
Total liabilities and partners’ capital (deficit)
$
307,588

 
 
$
224,355


See accompanying notes to consolidated financial statements.


F- 4



WESTMORELAND RESOURCE PARTNERS, LP AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF OPERATIONS
(in thousands, except for unit and per unit data) 
 
 
Westmoreland Resource Partners, LP
 
 
Oxford Resource Partners, LP
 
(Successor)(1)
 
 
(Predecessor)
 
Period of December 31,
 
 
Period from January 1, 2014 through December 31,
 
For the Year Ended December 31,
 
2014
 
 
2014
 
2013
 
2012
Revenues:
 
 
 
 
 
 
 
 
Coal revenues
$

 
 
$
295,662

 
$
336,201

 
$
364,928

Royalty revenues

 
 
284

 
8

 
1,496

Non-coal revenues

 
 
26,317

 
10,558

 
7,103

Total Revenues

 
 
322,263

 
346,767

 
373,527

Costs and expenses:
 
 
 
 
 
 
 
 
Cost of coal revenues

 
 
258,575

 
290,427

 
312,467

Cost of non-coal revenues

 
 
1,700

 
1,619

 
1,195

Depreciation, depletion and amortization

 
 
39,315

 
48,081

 
51,170

Selling and administrative

 
 
20,510

 
17,297

 
15,629

(Gain) loss on sales of assets

 
 
(218
)
 
(6,488
)
 
(8,021
)
Restructuring and impairment charges
2,783

 
 
75

 
1,761

 
15,650

Total cost and expenses
2,783

 
 
319,957

 
352,697

 
388,090

Operating (loss) income
(2,783
)
 
 
2,306

 
(5,930
)
 
(14,563
)
Other (expense) income:
 
 
 
 
 
 
 
 
Interest expense

 
 
(27,787
)
 
(20,246
)
 
(11,500
)
Interest income

 
 
4

 
4

 
10

(Loss) gain on debt extinguishment
(1,623
)
 
 
500

 
(808
)
 

Change in fair value of warrants

 
 
822

 
3,280

 

Total other expenses
(1,623
)
 
 
(26,461
)
 
(17,770
)
 
(11,490
)
Net loss
(4,406
)
 
 
(24,155
)
 
(23,700
)
 
(26,053
)
Less net loss (income) attributable to noncontrolling interest

 
 
1,270

 
(1,225
)
 
(755
)
Net loss attributable to WMLP unitholders
(4,406
)
 
 
(22,885
)
 
(24,925
)
 
(26,808
)
Less net loss allocated to general partner
(28
)
 
 
(429
)
 
(497
)
 
(535
)
Net loss allocated to limited partners
$
(4,378
)
 
 
$
(22,456
)
 
$
(24,428
)
 
$
(26,273
)
 
 
 
 
 
 
 
 
 
Net loss per limited partner unit:
 
 
 
 
 
 
 
 
Basic
$
(0.72
)
 
 
$
(10.92
)
 
$
(12.84
)
 
$
(15.24
)
Diluted
$
(0.72
)
 
 
$
(10.92
)
 
$
(12.84
)
 
$
(15.24
)

 
 
 
 
 
 
 
 
Weighted average number of limited partner units outstanding:
 
 
 
 
 
 
 
 
Basic
5,671,644

 
 
2,063,983

 
1,898,040

 
1,725,996

Diluted
5,671,644

 
 
2,063,983

 
1,898,040

 
1,725,996


 
 
 
 
 
 
 
 
Distributions paid per unit:
 
 
 
 
 
 
 
 
Limited partners:
 
 
 
 
 
 
 
 
Common
$

 
 
$

 
$

 
$
18.1500

Subordinated
$

 
 
$

 
$

 
$
7.6500

General partner
$

 
 
$

 
$

 
$
12.9000

(1)See Note 3.
See accompanying notes to consolidated financial statements. 

F- 5



WESTMORELAND RESOURCE PARTNERS, LP AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF PARTNERS’ CAPITAL (DEFICIT)
(in thousands, except for unit data) 
 
 
Limited Partners
 
 
 
 
 
 
 
Total
Partners'
Capital
(Deficit)
 
Common
 
Subordinated
 
Total
 
General Partner
 
Non-
controlling
Interest
 
Predecessor
Units
 
Capital
 
Units
 
Deficit
 
Units
 
Capital (Deficit)
 
Units
 
Deficit
 
 
Balance at December 31, 2011
868,312

 
$
121,911

 
856,698

 
$
(64,751
)
 
1,725,010

 
$
57,160

 
35,170

 
$
(1,032
)
 
$
2,989

 
$
59,117

Net (loss) income

 
(13,237
)
 

 
(13,036
)
 

 
(26,273
)
 

 
(535
)
 
755

 
(26,053
)
Partner contributions

 

 

 

 

 

 
121

 
12

 

 
12

Partner distributions

 
(15,772
)
 

 
(6,550
)
 

 
(22,322
)
 

 
(455
)
 

 
(22,777
)
Equity-based compensation

 
1,262

 

 

 

 
1,262

 

 

 

 
1,262

Issuance of units to LTIP participants
5,922

 
(234
)
 

 

 
5,922

 
(234
)
 

 

 

 
(234
)
Balance at December 31, 2012
874,234

 
93,930

 
856,698

 
(84,337
)
 
1,730,932

 
9,593

 
35,291

 
(2,010
)
 
3,744

 
11,327

Net (loss) income

 
(12,374
)
 

 
(12,054
)
 

 
(24,428
)
 

 
(497
)
 
1,225

 
(23,700
)
Equity-based compensation

 
1,441

 

 

 

 
1,441

 

 

 

 
1,441

Issuance of units to LTIP participants
9,657

 
(66
)
 

 

 
9,657

 
(66
)
 

 

 

 
(66
)
Balance at December 31, 2013
883,891

 
82,931

 
856,698

 
(96,391
)
 
1,740,589

 
(13,460
)
 
35,291

 
(2,507
)
 
4,969

 
(10,998
)
Net (loss) income

 
(12,053
)
 

 
(10,403
)
 

 
(22,456
)
 

 
(429
)
 
(1,270
)
 
(24,155
)
Redemption of noncontrolling interest

 
302

 

 
261

 

 
563

 

 
11

 
(3,699
)
 
(3,125
)
Equity-based compensation


 
4,559

 

 

 

 
4,559

 

 

 

 
4,559

Issuance of units to LTIP participants
108,696

 
(773
)
 

 

 
108,696

 
(773
)
 

 

 

 
(773
)
Predecessor balance at December 31, 2014
992,587

 
74,966

 
856,698

 
(106,533
)
 
1,849,285

 
(31,567
)
 
35,291

 
(2,925
)
 

 
(34,492
)
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Successor
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Purchase accounting adjustment

 
(64,191
)
 

 
106,533

 

 
42,342

 

 
36,425

 

 
78,767

Successor net (loss) income

 
(4,378
)
 

 

 

 
(4,378
)
 

 
(28
)
 

 
(4,406
)
Kemmerer coal reserve contribution
4,512,500

 
33,152

 

 

 
4,512,500

 
33,152

 

 

 

 
33,152

Successor balance at December 31, 2014
5,505,087

 
$
39,549

 
856,698

 
$

 
6,361,785

 
$
39,549

 
35,291

 
$
33,472

 
$

 
$
73,021

 
See accompanying notes to consolidated financial statements. 

F- 6



WESTMORELAND RESOURCE PARTNERS, LP AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF CASH FLOWS
(in thousands) 

 
Westmoreland Resource Partners, LP
 
 
Oxford Resource Partners, LP
 
(Successor)
 
 
(Predecessor)
 
Period of December 31,
 
 
Period from January 1, 2014 through December 31,
 
For the Year Ended December 31,
 
2014
 
 
2014
 
2013
 
2012
Cash flows from operating activities:
 
 
 
 
 
 
 
 
Net loss
$
(4,406
)
 
 
$
(24,155
)
 
$
(23,700
)
 
$
(26,053
)
Adjustments to reconcile net loss to net cash provided by operating activities:
 
 
 
 
 
 
 
 
Depreciation, depletion and amortization

 
 
39,088

 
47,827

 
50,928

Accretion of asset retirement obligations

 
 
2,337

 
2,293

 
1,567

Amortization of intangible assets and liabilities, net

 
 
227

 
254

 
242

Restructuring and impairment charges
2,783

 
 
75

 
1,761

 
15,650

Equity-based compensation

 
 
4,559

 
1,441

 
1,262

Gain on sale of oil and gas rights

 
 
(232
)
 
(6,116
)
 
(6,329
)
Loss (gain) on sales of assets

 
 
14

 
(372
)
 
(1,692
)
Non-cash interest expense

 
 
7,744

 
4,094

 

Amortization of deferred financing costs

 
 
4,099

 
3,178

 
2,175

Other

 
 
(822
)
 
(3,352
)
 
(767
)
Loss on extinguishment of debt
1,623

 
 
(500
)
 
808

 

Changes in operating assets and liabilities:
 
 
 
 
 
 
 
 
Receivables, net
(300
)
 
 
3,313

 
(6,062
)
 
8,596

Inventories

 
 
(1,161
)
 
(778
)
 
(554
)
Accounts payable and accrued expenses
(198
)
 
 
(4,859
)
 
(2,881
)
 
(518
)
Deferred revenue

 
 

 
(106
)
 
2,300

Accrued compensation

 
 
(1,858
)
 
1,760

 
(905
)
Asset retirement obligations

 
 
(4,354
)
 
(8,222
)
 
(8,966
)
Other assets and liabilities
(1,322
)
 
 
870

 
(2,111
)
 
(5,160
)
Net cash provided by operating activities
(1,820
)
 
 
24,385

 
9,716

 
31,776

Cash flows from investing activities:
 
 
 
 
 
 
 
 
Additions to property, plant and equipment

 
 
(15,903
)
 
(22,332
)
 
(22,687
)
Change in restricted investments and bond collateral

 
 
4,456

 
(9,590
)
 
1,811

Net proceeds from sales of assets

 
 
3,194

 
6,424

 
12,417

Insurance proceeds

 
 

 
3,035

 
400

Net cash used in investing activities

 
 
(8,253
)
 
(22,463
)
 
(8,059
)
Cash flows from financing activities:
 
 
 
 
 
 
 
 
Borrowings from long-term debt, net of debt discount
175,000

 
 
(6
)
 
150,000

 

Repayments of long-term debt
(135,822
)
 
 
(18,626
)
 
(56,072
)
 
(10,921
)
Borrowings on revolving lines of credit

 
 
22,500

 
53,588

 
51,000

Repayment on revolving lines of credit
(23,000
)
 
 
(19,000
)
 
(126,088
)
 
(39,000
)
Debt issuance costs and other refinancing costs
(8,437
)
 
 
(529
)
 
(9,569
)
 
(1,086
)
Redemption of noncontrolling interest

 
 
(3,560
)
 

 

Distributions to partners

 
 

 

 
(22,777
)
Capital contributions from partners

 
 

 

 
12

Net cash provided by (used in) financing activities
7,741

 
 
(19,221
)
 
11,859

 
(22,772
)
Net increase (decrease) in cash and cash equivalent
5,921

 
 
(3,089
)
 
(888
)
 
945

Cash and cash equivalents, beginning of the year

 
 
3,089

 
3,977

 
3,032

Cash and cash equivalents, end of the year
$
5,921

 
 
$

 
$
3,089

 
$
3,977


F- 7



WESTMORELAND RESOURCE PARTNERS, LP AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF CASH FLOWS
(in thousands) 

 
Westmoreland Resource Partners, LP
 
 
Oxford Resource Partners, LP
 
(Successor)
 
 
(Predecessor)
 
Period of December 31,
 
 
Period from January 1, 2014 through December 31,
 
For the Year Ended December 31,
 
2014
 
 
2014
 
2013
 
2012
Supplemental disclosures of cash flow information:
 
 
 
 
 
 
 
 
Cash paid for interest
$
2,922

 
 
$
14,655

 
$
12,258

 
$
10,739

Non-cash transactions:
 
 
 
 
 
 
 
 
Property, plant and equipment acquired with debt

 
 
35

 
1,000

 
307

Asset retirement obligations capitalized in mine development

 
 
5,385

 
8,927

 
16,011

Value of debt assigned to warrants

 
 

 
7,879

 

Market value of common units vested in LTIP

 
 
1,320

 
330

 
849

Kemmerer coal reserves contribution
33,152

 
 

 

 

 See accompanying notes to consolidated financial statements. 

F- 8

WESTMORELAND RESOURCE PARTNERS, LP AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(in thousands, except for unit and per unit data)


NOTE 1:ORGANIZATION AND PRESENTATION
Basis of Presentation and Principles of Consolidation
The accompanying consolidated financial statements include the accounts and operations of the Partnership and its consolidated subsidiaries and are prepared in conformity with accounting principles generally accepted in the United States of America (“US GAAP”). WCC's cost of acquiring our GP has been pushed-down to establish a new accounting basis for us beginning in the last minutes of the year ended December 31, 2014. Accordingly, the accompanying consolidated financial statements are presented for two periods, Predecessor and Successor, which relate to the accounting periods preceding and succeeding the completion of the transaction. The Predecessor and Successor periods have been separated by a vertical line on the face of the consolidated financial statements to highlight the facts that the financial information for such periods has been prepared under two different historical-cost bases of accounting.
Significant Relationships Referenced in Notes to Consolidated Financial Statements
“We,” “us,” “our,” “WMLP,” or the "Partnership” means the business and operations of Westmoreland Resource Partners, LP, the parent entity, as well as its consolidated subsidiaries.
Our “GP” means Westmoreland Resources GP, LLC, the general partner of Westmoreland Resource Partners, LP.
Westmoreland Coal Company Transactions
Acquisition of Oxford Resources GP, LLC
On December 31, 2014, pursuant to a Purchase Agreement dated October 16, 2014, Westmoreland Coal Company, a Delaware corporation (“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 of our former second lien term loan lenders and their affiliates (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 subordinated units 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 Fee Coal Reserves
On December 31, 2014, pursuant to a Contribution Agreement dated October 16, 2014, WCC contributed to us 100% of the membership interests in Westmoreland Kemmerer Fee Coal Holdings, LLC (“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 a 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 Mine fee coal reserves will generate minimum royalty payments 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
In anticipation of the WCC transactions, 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.

F- 9

WESTMORELAND RESOURCE PARTNERS, LP AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(in thousands, except for unit and per unit data)

Equity 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:
Effect a 12-to-1 reverse split of our common and general partner units;
Convert all of our outstanding subordinated units to liquidation units (with no non-liquidating distribution or voting rights);
Waive and eliminate our current cumulative common unit arrearages and also eliminate the concept of common unit arrearages going forward;
Reset the minimum quarterly distribution to $0.1333 per common unit;
Restructure the incentive distribution rights (the “IDRs”) held by our GP to provide that the IDRs will be entitled to receive (i) 13% of quarterly distributions over $0.1533 per unit and up to $0.1667 per unit; (ii) 23% of quarterly distributions over $0.1667 per unit and up to $0.2000 per unit; and (iii) 48% of quarterly distributions over $0.2000 per unit; and
Suspend the distributions on the IDRs for six quarters, provided that such suspension may be reduced to three quarters if, during the suspension period, additional drop down transactions aggregating greater than $35.0 million in enterprise value are undertaken by us or our affiliates that are reasonably expected to provide accretion to per unit common unitholder distributions.
Special Distribution to Public Unitholders
Following the WCC transactions, we made a one-time special distribution to our public unitholders. The distribution was made on a pro rata basis, and consisted of a 25% unit dividend of 206,549 in additional post-reverse split common units. Throughout the consolidated financial statements, unit and per unit amounts have been adjusted for the 12-to-1 reverse unit split effective December 31, 2014.
Debt Refinancing
In connection with the WCC transactions, we entered into a new $295 million 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 consisting of (i) a first lien $75 million term loan and $25 million revolving credit facility and (ii) a second lien $75 million term loan. 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.
Organization
WCC directly owns all the common units of our GP. WCC’s common stock trades on the Nasdaq under the symbol “WLB.”
As of March 3, 2015, WCC and its consolidated subsidiaries owned, through their limited and general partner interests in us, an approximate 79.1% interest in us. In addition to any distributions it receives from its limited and general partner interests, WCC holds indirectly the incentive distribution rights in us held by our GP. Distributions were not permitted under our credit facilities in effect until the end of 2014, and no distributions were made in 2014.
Westmoreland Resource Partners, LP is a Delaware limited partnership formed in August 2007. 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 long-term coal sales contracts. We focus on acquiring thermal coal reserves that we can

F- 10

WESTMORELAND RESOURCE PARTNERS, LP AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(in thousands, except for unit and per unit data)

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, Oxford Mining Company-Kentucky, LLC, WKFCH 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 or lease our controlled coal reserves to others to mine.
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 both underground and surface 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.    
NOTE 2:SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES
Use of Estimates
The preparation of financial statements in conformity with GAAP requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosures of contingent assets and liabilities at the date of the financial statements and reported amounts of revenues and expenses during the reporting period. Actual results could differ from those estimates.
Purchase and Pushdown Accounting
WCC's acquisition of our GP was accounted for using the acquisition method under ASC 805, Business Combination. Under the acquisition method, the purchase price was allocated to the underlying tangible and intangible assets acquired and liabilities assumed based on their respective fair values. The allocation of the purchase price is preliminary pending the completion of various analyses and the finalization of estimates. During the measurement period (which is not to exceed one year from the acquisition date), additional assets or liabilities may be recognized if new information is obtained about facts and circumstances that existed as of the acquisition date that, if known, would have resulted in the recognition of those assets or liabilities as of that date. The preliminary allocation may be adjusted after obtaining additional information regarding, among other things, asset valuations, liabilities assumed and revisions of previous estimates. These adjustments may be significant and will be accounted for retrospectively.
Per ASC 805-50-25-4 (effective November 18, 2014), we, as an acquiree of WCC through our GP, have the option to apply pushdown accounting in our consolidated financial statements when an acquirer (WCC) obtained control of us. We have chosen adopt pushdown accounting and will reflect purchase accounting adjustments in our consolidated financial statement.
Cash
Cash consists of cash held with reputable depository institutions and is stated at cost which approximates fair value. At times, such deposits may be in excess of the FDIC insurance limit. We have not experienced any losses in such accounts and believe we are not exposed to any significant credit risk relating to such amounts.
Trade Receivables
Trade receivables are recorded at the invoiced amount and do not bear interest. The Partnership evaluates the need for an allowance for doubtful accounts based on a review of collectability. There was no allowance for doubtful accounts as of December 31, 2014 and 2013.
Inventory
Inventory, which includes materials and supplies as well as raw coal, is stated at the lower of cost or market. Cost is determined using the average cost method. Coal inventory costs include labor, supplies, equipment, operating overhead and other related costs.

F- 11

WESTMORELAND RESOURCE PARTNERS, LP AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(in thousands, except for unit and per unit data)

Restricted Investments and Bond Collateral
We had restricted cash related to Harrison Resources of $3,969 as of December 31, 2013, which is included in our consolidated balance sheets as Restricted investments and bond collateral. Harrison Resources’ cash, which is deemed to be restricted due to the limitations of its use for Harrison Resources’ operations, primarily relates to funds set aside for future reclamation obligations. There are not any further restrictions on Harrison Resources' cash following the redemption of the noncontrolling interest effective October 1, 2014. See the Noncontrolling Interest section of this Note 2 and Note 15.
Exploration and Mine Development
Exploration expenditures are charged to Cost of coal revenues as incurred, including costs related to drilling and study costs incurred to convert or upgrade mineral resources to reserves.
At existing surface mines, additional pits may be added to increase production capacity. These expansions may require significant capital to purchase or relocate equipment, build or improve existing haul roads and create the initial cut to remove overburden for new pits at existing mines. If these pits operate in a separate and distinct area of the mine, the costs associated with initially uncovering coal for production are capitalized and amortized over the life of the developed pit consistent with coal industry practices. Once production has begun, mining costs are then expensed as incurred.
Where new pits are routinely developed as part of a contiguous mining sequence, the Partnership expenses such costs as incurred. The development of a contiguous pit typically reflects the planned progression of an existing pit, thus maintaining production levels from the same mining area utilizing the same employee group and equipment.
Property, Plant and Equipment
Property, plant and equipment are recorded at cost or fair value as a result of purchase accounting as previously discussed. Expenditures that extend the useful lives of existing plant and equipment or increase productivity of the assets are capitalized. Maintenance and repair costs that do not extend the useful life or increase productivity of the asset are expensed as incurred. Coal reserves are recorded at cost, or at fair value originally in the case of acquired businesses and application of pushdown accounting.
Coal reserves, mineral rights and mine development costs are depleted based upon estimated recoverable proven and probable reserves. Plant and equipment are depreciated on a straight-line basis over the assets’ estimated useful lives as follows:
 
Years
Buildings and tipple
25 - 39
Machinery and equipment
 1 - 12
Vehicles
5 - 7
Furniture and fixtures
3 - 7
We assess the carrying value of our property, plant and equipment for impairment whenever events or changes in circumstances indicate that the carrying amount of an asset may not be recoverable. Recoverability is measured by comparing estimated undiscounted cash flows expected to be generated from such assets to their net book value. If net book value exceeds estimated cash flows, the asset is written down to fair value. When an asset is retired or sold, its cost and related accumulated depreciation and depletion are removed from the accounts. The difference between the net book value of the asset and proceeds on disposition is recorded as a gain or loss. Fully depreciated plant and equipment still in use are not eliminated from the accounts. Amortization of capital leases is included in Depreciation, depletion and amortization.
Advanced Coal Royalties
A portion of our reserves are leased. Advanced coal royalties are advance payments made to lessors under terms of lease agreements that are typically recoupable through an offset or credit against royalties payable on future production. We write-off advanced coal royalties when recoverability is no longer probable based on future mining plans.

F- 12

WESTMORELAND RESOURCE PARTNERS, LP AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(in thousands, except for unit and per unit data)

Deferred Financing Costs
We capitalize costs incurred in connection with borrowings or establishment of credit facilities and issuance of debt securities. These costs are amortized as an adjustment to interest expense over the life of the borrowing or term of the credit facility using the effective interest method. These amounts are recorded in Deferred financing costs, net in the accompanying consolidated balance sheets.
Financial Instruments
Our financial instruments include cash, accounts receivable, restricted investments and bond collateral, accounts payable, fixed rate debt and variable rate debt. In 2012, we also had an interest rate swap agreement. We do not hold or purchase financial instruments or derivative financial instruments for trading purposes.
Our financial instruments include fixed price forward contracts for diesel fuel. Our risk management policy allows us to purchase up to 80% of our unhedged diesel fuel gallons on fixed price forward contracts. These contracts meet the normal purchases and sales exclusion and therefore are not accounted for as derivatives. These forward fuel contracts usually have a term of 1 year or less, and we take physical delivery of all the fuel supplied under these contracts except in the case of one Illinois Basin contract which was modified in connection with its cancellation.
Warrants
In connection with our refinancing in June 2013, certain of the second lien lenders and lender affiliates received warrants entitling them to purchase common and subordinated units under a freestanding contract. The subordinated unit warrants were canceled on December 31, 2014. Pursuant to Financial Accounting Standards Board's Codification Topic 470-20, “Debt With Conversion and Other Options” (ASC 470-20), freestanding contracts that are settled in a company’s own stock, including common and subordinated unit warrants, are to be designated as an asset, liability or equity instrument. Both the common and subordinated unit warrants were determined to be liabilities and were recorded at fair value as determined using the Black-Scholes Pricing Model. ASC 470-20 further requires that the warrants' fair value be remeasured each reporting period, with the change in fair value being reported in the consolidated statements of operations. Fair value determinations prepared using the Black-Scholes Pricing Model require assumptions related to interest rates, unit price, exercise price, term and volatilities.
Intangible Assets
Identifiable intangible assets acquired in a business combination must be recognized and reported separately from goodwill. These intangible assets are amortized on a straight-line basis over the respective useful life of the asset. See Note 8 for further details.
Deferred Revenue
Deferred revenues represent funding received upon the negotiation of contracts for coal royalty and limestone sales. These deferred revenues are recognized as deliveries of the reserved coal or limestone are made in accordance with the contracts. At December 31, 2014, deferred revenue was adjusted to fair value of zero in purchase accounting since there is no future legal performance obligation of the Successor.
Asset Retirement Obligations
Our asset retirement obligations, or ARO, primarily consists of estimated costs to reclaim surface land and support facilities at our mines and in accordance with federal and state reclamation laws as established by each mining permit.
We estimate ARO for final reclamation and mine closure based upon detailed engineering calculations of the amount and timing of the future costs for a third party to perform the required work. These estimates are based on projected pit configurations at the end of mining and are escalated for inflation, and then discounted at a credit adjusted risk-free rate. We record mineral rights associated with the initial recorded liability. Mineral rights are amortized based on the units of production method over the estimated recoverable, proven and probable reserves at the related mine, and the ARO is accreted to the projected settlement date. Changes in estimates could occur due to revisions of mine plans, changes in estimated costs, and changes in timing of the performance of reclamation activities. See Note 10.

F- 13

WESTMORELAND RESOURCE PARTNERS, LP AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(in thousands, except for unit and per unit data)

Income Taxes
As a partnership, we are not a taxable entity for federal or state income tax purposes; the tax effect of our activities passes through to our unitholders. Therefore, no provision or liability for federal or state income taxes is included in our financial statements. Net income (loss) for financial statement purposes may differ significantly from taxable income (loss) reportable to our unitholders as a result of timing or permanent differences between financial reporting under US GAAP and the regulations promulgated by the Internal Revenue Service.
Revenue Recognition
Revenue from coal sales is recognized at the time title and risk of loss passes to the customer in accordance with the terms of the underlying sales agreements and after any contingent performance obligations have been satisfied. Coal sales prices are subject to premiums and reductions based on variations in coal quality delivered versus specifications in our coal supply contracts, but such adjustments are typically confirmed in a matter of days. Risk of loss typically transfers to the customer at the mine or dock, when the coal is loaded on the rail, barge, or truck.
Royalty revenue relates to coal reserves which we lease to others and oil and gas rights. For the years ended 2014, 2013 and 2012, we received royalties of $0.3 million, $0.01 million and $1.5 million, respectively.
Non-coal revenue consists primarily of clay and limestone sales, service fees, and other miscellaneous revenue. Clay and limestone sales relate to material we recover during the coal mining process and sell to third parties. Additionally service fees are earned for operating a coal unloading facility, providing river barge loading services, and hauling ash. Periodically, we recognize miscellaneous revenue related to lost coal claims that result from granting third-party right-of-way access through small portions of various mine complexes. In 2014, we also received $19.5 million from a former customer to compensate us for lost profits on a wrongfully terminated contract.
Below-Market Coal Sales Contracts
Our below-market coal sales contracts were acquired through the Phoenix Coal acquisition in 2009 and represent contracts for which the prevailing market price for the specified coal was in excess of the contract price. The fair value was based on discounted cash flows resulting from the difference between the below-market contract price and the prevailing market price at the date of acquisition. The fair value adjustments are amortized into coal sales on the basis of tons shipped over the terms of the respective contracts. Amortization of these below-market contracts included in revenue was $0.1 million and $0.6 million for the years ended December 31, 2013 and 2012, respectively. The current portion of the net carrying value of our below-market coal sales contracts was reflected in our consolidated balance sheets as Other current liabilities. No such amounts remained at December 31, 2013.
Equity-Based Compensation
Equity-based compensation expense is generally measured at the grant date and recognized as expense over the vesting period of the entire award. These costs are recorded in Cost of coal revenues and Selling and administrative in the accompanying consolidated results of operations. See Note 13.
Noncontrolling Interest
Noncontrolling interest is reported as a separate component of equity. The amount of net income (loss) attributable to the noncontrolling interest is recorded in Net income (loss) attributable to noncontrolling interest in our consolidated statements of operations. See Note 15.
Earnings (Losses) Per Unit
For purposes of our earnings per unit calculation, we apply the two class method. All outstanding limited partner units and general partner units share pro rata in income (loss) allocations and distributions, but only our general partner has voting rights. Limited partner units are further segregated into common units and subordinated units. As of December 31, 2014, the subordinated units were converted to liquidation units.

F- 14

WESTMORELAND RESOURCE PARTNERS, LP AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(in thousands, except for unit and per unit data)

Limited Partner Units: Basic earnings (losses) per unit are computed by dividing net income (loss) attributable to limited partners by the weighted average units outstanding, including unexercised participating warrants, during the reporting period. Diluted earnings (losses) per unit are computed similar to basic earnings (losses) per unit except that the weighted average units outstanding and net income (loss) attributable to limited partners are increased to include the dilutive effect of phantom units that would be issued assuming conversion to limited partnership units upon vesting. No such items were included in the computation of diluted loss per unit for the years ended 2014, 2013 or 2012 because we incurred a loss in each of these periods and the effect of inclusion would have been anti-dilutive.
General Partner Units: Basic earnings (losses) per unit are computed by dividing net income (loss) attributable to our GP by the weighted average units outstanding, including unexercised participating warrants, during the reporting period. Diluted earnings (losses) per unit for our GP are computed similar to basic earnings (losses) per unit except that the net income (loss) attributable to the general partner units is adjusted for the dilutive impact of the phantom units. No such items were included in the computation of diluted loss per unit for the years ended 2014, 2013 or 2012 because we incurred a loss in each of these periods and the effect of inclusion would have been anti-dilutive.
The table below shows the number of units that were excluded from the calculation of diluted loss per unit because their inclusion would be anti-dilutive to the calculation:
 
Year Ended December 31,
 
2014
 
2013
 
2012
Long-term incentive plan units
70,298

 
42,694

 
371

Accounting Pronouncement Effective in the Future
In April 2014, the FASB issued ASU 2014-8, Presentation of Financial Statements and Property, Plant and Equipment, which changes the presentation of discontinued operations on the statements of operations and other requirements for reporting discontinued operations. Under the new standard, a disposal of a component or a group of components of an entity is required to be reported in discontinued operations if the disposal represents a strategic shift that has (or will have) a major effect on an entity’s operations and financial results when the component meets the criteria to be classified as held for sale or is disposed. The amendments in this update also require additional disclosures about discontinued operations and disposal of an individually significant component of an entity that does not qualify for discontinued operations. The new guidance is effective for interim and annual periods beginning after December 15, 2014. We adopted ASU 2014-8 effective January 1, 2015.
In May 2014, the FASB issued ASU 2014-9, Revenue From Contracts With Customers, which outlines a single comprehensive model for entities to use in accounting for revenue arising from contracts with customers and supersedes most current revenue recognition guidance, including industry-specific guidance. The ASU is based on the principle that an entity should recognize revenue to depict the transfer of goods or services to customers in an amount that reflects the consideration which the entity expects to be entitled to receive in exchange for those goods or services. The ASU also requires additional disclosure about the nature, amount, timing and uncertainty of revenue and cash flows arising from customer contracts, including significant judgments and changes in judgments and assets recognized from costs incurred to fulfill a contract. Entities have the option of using either a full retrospective or a modified retrospective approach for the adoption of the new standard. The new guidance is effective for the interim and annual periods beginning after December 15, 2016; early adoption is not permitted. We are currently assessing the impact that this standard will have on our consolidated financial statements.
In August 2014, the FASB issued ASU 2014-15, Presentation of Financial Statements-Going Concern (Subtopic 205-40): Disclosure of Uncertainties about an Entity’s Ability to Continue as a Going Concern, which is intended to define management’s responsibility to evaluate whether there is substantial doubt about an organization’s ability to continue as a going concern and to provide related footnote disclosures. Under GAAP, financial statements are prepared based on the presumption that the reporting organization will continue to operate as a going concern, except in limited circumstances. Financial reporting under this presumption is commonly referred to as the going concern basis of accounting. The going concern basis of accounting is critical to financial reporting because it establishes the fundamental basis for measuring and classifying assets and liabilities. Currently, GAAP lacks guidance about management’s responsibility to evaluate whether there is substantial doubt about the organization’s ability to continue as a going concern or to provide related footnote disclosures. This ASU provides guidance to an organization’s management, with principles and definitions that are intended to reduce diversity in the timing and content of disclosures that are commonly provided by organizations today in the financial statement footnotes. The new guidance is effective for the interim and annual periods beginning after December 15, 2016; early adoption is permitted for annual or interim reporting periods for which the financial statements have not previously been issued.

F- 15

WESTMORELAND RESOURCE PARTNERS, LP AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(in thousands, except for unit and per unit data)

In August 2014, the FASB issued ASU 2014-17, Pushdown Accounting, which allows entities the option to elect pushdown of purchase accounting each time there is a change-in-control event in which an acquirer obtains control of the acquiree. If an acquiree does not initially elect to apply pushdown accounting upon a change-in-control event, it can subsequently elect to apply pushdown accounting to its most recent change-in-control event in a later reporting period as a change in accounting principle. Once made, the election to apply pushdown accounting is irrevocable. Entities applying pushdown accounting are required to measure the individual assets and liabilities of the acquired entity based on the measurement guidance in ASC 805, including the recognition of goodwill. However, any bargain purchase gain recognized by the acquirer should not be recognized in the acquiree’s income statement, but rather as an adjustment to additional paid-in capital. Acquisition-related debt is recognized by the acquiree only if the acquired entity is required to recognize a liability for debt in accordance with other applicable guidance. See our application of ASU 2014-17 in Note 3.
Reclassifications
Certain prior-year amounts have been reclassified in our consolidated balance sheets, statements of operations and statements of cash flows as of December 31, 2013 and 2012 to conform with the financial statement line items used by our GP's parent, WCC.
NOTE 3:    ACQUISITION AND PUSHDOWN ACCOUNTING
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 and 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, 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 subordinated units 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.
The purchase consideration for our GP and control of our GP’s consolidated subsidiaries is estimated at $238.3 million, which included $33.5 million paid in cash, plus the assumption of approximately $194.0 million of liabilities. Additionally, we incurred acquisition-related costs of $5.5 million that have been expensed and are included in Selling and administrative in the accompanying consolidated results of operations.
The acquisition of our GP was accounted for by WCC under the acquisition method of accounting that requires the total purchase consideration to be allocated to the assets acquired and liabilities assumed based on estimates of fair value. We have elected to apply pushdown accounting to our consolidated financial statements. By applying pushdown accounting, our financial statements also reflect these adjustments to fair value with a portion allocated to noncontrolling interest for the portion of us that is not owned directly by WCC.
The allocation of the purchase price is preliminary pending the completion of various analyses and the finalization of estimates. During the measurement period (which is not to exceed one year from the acquisition date), additional assets or liabilities may be recognized if new information is obtained about facts and circumstances that existed as of the acquisition date that, if known, would have resulted in the recognition of those assets or liabilities as of that date. The preliminary allocation may be adjusted after obtaining additional information regarding, among other things, asset valuations, liabilities assumed and revisions of previous estimates. These adjustments may be significant and will be accounted for retrospectively.

F- 16

WESTMORELAND RESOURCE PARTNERS, LP AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(in thousands, except for unit and per unit data)

A summary of the estimated purchase consideration and a preliminary allocation of the estimated purchase consideration is as follows (in millions):
Estimated purchase consideration
 
Market value of limited partners' units
$
10.8

Cash paid
33.5

Total consideration
$
44.3

 
 
Estimated fair value of liabilities assumed:
 
Debt
$
160.1

Asset retirement obligations
31.7

Other liabilities
0.2

Warrants
2.0

Total estimated fair value of liabilities assumed
194.0

Total estimated purchase consideration:
$
238.3

 
 
Preliminary allocation of estimated purchase consideration:
 
Working capital
$
14.7

Land and mineral rights
38.6

Plant and equipment
134.0

Advanced coal royalities
9.2

Restricted investments and bond collateral
10.6

Intangible asset
31.0

Other assets
0.2

Total preliminary allocation of estimated purchase consideration:
$
238.3

Subsequent to the acquisition of our GP, the following events occurred which are activity of the new owners or Successor entity. The aquisition triggered change of control provisions in the executives’ employment contracts which resulted in additional restructuring expenses. See Note 4. Subsequent to the transaction, we also refinanced our debt which included an early payment penalty included in debt extinguishment costs.
NOTE 4:RESTRUCTURING AND IMPAIRMENT CHARGES
WCC Transactions Restructuring
Concurrent with the WCC transactions, a restructuring plan was initiated to streamline operations and eliminate duplicate roles and responsibilities between us and WCC. At December 31, 2014, we recorded restructuring charges for employee termination benefits of $2.8 million. We expect to incur $0.6 million of additional restructuring costs as we complete our restructuring plan throughout the first half of 2015.
WCC transactions restructuring accrual activity is summarized as follows:
 
Oxford Resource Partners, LP (Predecessor)
 
 
Westmoreland Resource Partners, LP
(Successor)
 
As of December 31, 2014
 
 
For the Period
December 31, 2014
 
As of December 31, 2014
 
Liability
 
 
Charges
 
Payments
 
Liability
Severance and other termination costs
$

 
 
$
2,783

 
$

 
$
2,783


F- 17

WESTMORELAND RESOURCE PARTNERS, LP AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(in thousands, except for unit and per unit data)

Illinois Basin Restructuring and Impairment
In March 2012, we received a termination notice from a customer related to an 0.8 million ton per year coal supply contract fulfilled from our Illinois Basin operations. In response, we initially idled some of our Illinois Basin operations, terminated a significant number of employees related to such operations and substituted purchased coal for mined and washed coal on certain sales contracts. Subsequently over time, the remainder of our Illinois Basin operations were idled and the related employees terminated with the result that our Illinois Basin operations were fully idled as of December 31, 2013. During that period, we also sold some of our excess Illinois Basin equipment while redeploying most of the equipment to our Northern Appalachian operations, with such redeployment being completed during the first quarter of 2014. Additionally, we sold our Illinois Basin dock in April 2014. Finally, we are seeking to sell the remaining Illinois Basin equipment, consisting of a large-capacity shovel and several smaller pieces of equipment, and would consider offers to purchase the remaining coal reserves and/or facilities related to our Illinois Basin operations.
Impairment Charges
As a result of the restructuring described above, we recorded asset impairment charges of $12.8 million during 2012. These non-cash charges related to coal reserves, mine development assets and certain mining equipment. No such charges were recorded in the years ended December 31, 2014 and 2013, respectively.
Restructuring Charges
The restructuring related to our Illinois Basin operations was completed in March 2014. Restructuring charges of $0.1 million, $1.8 million and $2.9 million were incurred for the years ended December 31, 2014, 2013 and 2012, respectively. These charges included termination costs for employees, professional and legal fees, and transportation costs associated with moving idled equipment to our Northern Appalachian operations. The liabilities related to the restructuring are included in Other liabilities in our consolidated balance sheet as of December 31, 2013. There is no liability remaining for the Illinois Basin restructuring as of December 31, 2014.
Our Illinois Basin restructuring accrual activity is summarized as follows:
 
Oxford Resource Partners, LP (Predecessor)
 
As of December 31, 2013
 
Period from January 1, 2014 through December 31, 2014

As of December 31, 2014
 
Liability
 
Charges
 
Payments

Liability
Severance and other termination costs
$
404

 
$
(42
)
 
$
(362
)
 
$

Equipment relocation costs
252

 
117

 
(369
)
 

Total cash restructuring charges
$
656

 
$
75

 
$
(731
)
 
$


F- 18

WESTMORELAND RESOURCE PARTNERS, LP AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(in thousands, except for unit and per unit data)

The following table summarizes the total Illinois Basin restructuring and impairment charges incurred over the course of the restructuring:
 
Oxford Resource Partners, LP (Predecessor)
 
Charges
 
 
 
Period from January 1, 2014 through December 31, 2014
 
Incurred Through December 31,
2014
 
Total Expected
Charges
Cash:
 
 
 
 
 
Severance and other termination costs
$
(42
)
 
$
1,846

 
$
1,846

Professional and legal fees

 
1,021

 
1,021

Equipment relocation costs
117

 
1,161

 
1,161

Coal lease termination costs

 
23

 
23

Total cash restructuring charges
75

 
4,051

 
4,051

 
 
 
 
 
 
Non-cash:
 
 
 
 
 
Coal lease termination costs

 
683

 
683

Asset impairment

 
12,753

 
12,753

Total non-cash restructuring charges

 
13,436

 
13,436

Total restructuring and impairment charges
$
75

 
$
17,487

 
$
17,487

NOTE 5:INVENTORY
Inventory consisted of the following:
 
Westmoreland Resource Partners, LP
 
 
Oxford Resource Partners, LP
 
(Successor)
 
 
(Predecessor)
 
December 31,
 
 
December 31,
 
2014
 
 
2013
Coal
$
6,590

 
 
$
5,957

Fuel inventory
1,860

 
 
1,879

Materials and supplies
5,563

 
 
6,004

Total
$
14,013

 
 
$
13,840


F- 19

WESTMORELAND RESOURCE PARTNERS, LP AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(in thousands, except for unit and per unit data)

NOTE 6:NET PROPERTY, PLANT AND EQUIPMENT 
Property, plant and equipment, net of accumulated depreciation, depletion and amortization, consisted of the following:
 
Westmoreland Resource Partners, LP
 
 
Oxford Resource Partners, LP
 
(Successor)
 
 
(Predecessor)
 
December 31,
 
 
December 31,
 
2014
 
 
2013
Property, plant and equipment
 
 
 
 
Land
$
4,040

 
 
$
3,016

Mineral rights
67,675

 
 
107,651

Total land and mineral rights
71,715

 
 
110,667

Buildings and tipple
1,430

 
 
2,117

Machinery and equipment
131,640

 
 
202,663

Vehicles
527

 
 
4,522

Furniture and fixtures
432

 
 
1,584

Total plant and equipment
134,029

 
 
210,886

Total gross, property, plant and equipment
205,744

 
 
321,553

Less: accumulated depreciation, depletion and amortization

 
 
(177,127
)
Net property, plant and equipment
$
205,744

 
 
$
144,426

 
The amounts of depreciation expense related to owned and leased fixed assets, depletion expense related to owned and leased coal reserves, amortization expense related to mine development costs within mineral rights and amortization expense related to intangible assets for the respective years are as follows:
 
For the Year Ended December 31,
 
2014
 
2013
 
2012
Depreciation
$
26,663

 
$
30,786

 
$
34,276

Depletion
5,337

 
4,513

 
4,869

Mine development amortization
7,088

 
12,528

 
11,783

Intangible asset amortization(1)
227

 
254

 
242

 
$
39,315

 
$
48,081

 
$
51,170

(1)See Note 8.
In June 2013 and April 2012, we completed the sale of certain oil and gas rights and land in eastern Ohio for $6.1 million and $6.3 million, respectively, which is recorded in Gain on sales of assets in our consolidated statements of operations for the years ended December 31, 2013 and 2012. As part of these transactions, we retained royalty rights equivalent to 20% of net revenue once the wells are producing. These rights started generating royalty revenue during the first quarter of 2014, which is recorded in Royalty revenues.


F- 20

WESTMORELAND RESOURCE PARTNERS, LP AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(in thousands, except for unit and per unit data)

NOTE 7:OPERATING LEASES 
We lease certain operating facilities and equipment under non-cancelable lease agreements that expire on various dates through 2019. Generally, the lease terms range from three to ten years. As of December 31, 2014, aggregate lease payments under operating leases that have initial or remaining non-cancelable lease terms in excess of one year are set forth below:
For the years ending December 31, 2015
$
6,189

2016
2,871

2017
877

2018
227

2019
225

  
For the years ended December 31, 2014, 2013 and 2012, we incurred lease expenses of $8,835, $8,591 and $7,118, respectively. 
We have also entered into various coal reserve lease agreements under which advance royalty payments are made. Most of these advance royalty payments are recoupable against future royalty payments otherwise due based on production. Such payments are capitalized as Advanced coal royalties at the time of payment, and are recoupable through an offset or credit against royalties payable on future production.
NOTE 8:INTANGIBLE ASSETS 
Identifiable intangible assets acquired in a business combination must be recognized and reported separately from goodwill. In December 2014, as part of the preliminary purchase accounting consideration discussed in Note 3, we have determined that the most significant acquired identifiable intangible asset is related to a beneficial lease agreement. Intangible assets result from more favorable market prices than contracted prices in lease agreements as measured during a business combination. Our intangible asset is amortized on a straight-line basis over the remaining term of the lease agreement.
 
Westmoreland Resource Partners, LP (Successor)
 
As of December 31, 2014
 
Estimated
Remaining
Life (years)
 
Cost
 
Accumulated
Amortization
 
Net Carrying
Value
Intangible assets
 
 
 
 
 
 
 
Favorable lease agreement
15
 
$
31,000

 
$

 
$
31,000

 
 
Oxford Resource Partners, LP (Predecessor)
 
As of December 31, 2013
 
Estimated
Remaining
Life (years)
 
Cost
 
Accumulated
Amortization
 
Net Carrying
Value
Intangible assets
 
 
 
 
 
 
 
Customer relationships
13
 
$
3,315

 
$
2,127

 
$
1,188

 
Customer relationships represent intangible assets that were recorded at fair value when we acquired Oxford Mining and its subsidiaries in August 2007. The net carrying value of our customer relationships is reflected in our consolidated balance sheets as Intangible assets, net. We amortized these assets over the expected life of the respective customer relationships. This intangible asset was adjusted to fair value in purchase accounting for the WCC transactions at December 31, 2014. Amortization related to customer relationships totaled $227, $254, and $242 for the years ended December 31, 2014, 2013 and 2012, respectively. 

F- 21

WESTMORELAND RESOURCE PARTNERS, LP AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(in thousands, except for unit and per unit data)

Expected amortization of intangible assets will be approximately: 
For the years ending December 31, 2015
$
2,067

2016
2,067

2017
2,067

2018
2,067

2019
2,067

Thereafter
20,665

 
We evaluate our intangible assets for impairment when indicators of impairment exist. For the years ended December 31, 2014, 2013 and 2012, there were no indicators of impairment present for our intangible assets.
NOTE 9:OTHER CURRENT LIABILITIES
Other current liabilities consisted of the following: 
 
Westmoreland Resource Partners, LP
 
Oxford Resource Partners, LP
 
(Successor)
 
(Predecessor)
 
December 31,
 
December 31,
 
2014
 
2013
Accrued interest
$
45

 
$
1,424

Accrued royalties
809

 
1,062

Restructuring reserve
2,783

 

Other
370

 
971

Total
$
4,007

 
$
3,457

NOTE 10:ASSET RETIREMENT OBLIGATIONS 
As previously indicated, our asset retirement obligations arise from SMCRA and similar state statutes, which require that mine property be restored in accordance with specified standards and an approved reclamation plan. The required reclamation activities to be performed are outlined in our mining permits. These activities include reclaiming the pit and support acreage, as well as stream mitigation. 
As of December 31, 2014, our ARO totaled $31.7 million, including amounts reported as current liabilities. While the precise amount of these future costs cannot be determined with certainty, we estimate that, as of December 31, 2014, the aggregate undiscounted cost of final ARO is $42.4 million

F- 22

WESTMORELAND RESOURCE PARTNERS, LP AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(in thousands, except for unit and per unit data)

Activities affecting the liability for ARO for the respective years are as follows: 
 
Year Ended December 31,
 
2014
 
2013
Asset retirement obligations, January 1,
$
31,654

 
$
29,013

Accretion
2,337

 
2,293

Changes resulting from additional mines
5,171

 
3,671

Changes due to amount and timing of reclamation
(2,480
)
 
5,333

Payments
(4,997
)
 
(8,656
)
Asset retirement obligations, December 31,
31,685

 
31,654

Less current portion
(7,783
)
 
(5,996
)
Asset retirement obligations, less current portion
$
23,902

 
$
25,658

  
In 2014, the revisions in discounted estimated cash flows resulted in a net increase in the asset retirement obligations of $2.7 million. Of this amount, $5.2 million related to five new mines, $0.1 million related to reclamation work in progress at recently closed mines offset in part by a $2.6 million decrease related to updated cost estimates for pond removal, grading and water treatment. 
In 2013, the revisions in discounted estimated cash flows resulted in a net increase in the asset retirement obligations of $9.0 million. Of this amount, $3.7 million related to four new mines, $4.0 million related to reclamation work in progress at recently closed mines and the remaining $1.3 million related to updated cost estimates for pond removal, grading and water treatment.  
Adjustments to the liability for asset retirement obligations due to such revisions generally result in corresponding adjustments to the related mine development assets for active and new mines.
NOTE 11:LONG-TERM DEBT
Debt consisted of the following:
 
Westmoreland Resource Partners, LP
 
 
Oxford Resource Partners, LP
 
(Successor)
 
 
(Predecessor)
 
December 31,
 
 
December 31,
 
2014
 
 
2013
First lien debt:
 
 
 
 
Term loan
$
175,000

 
 
$
69,321

Revolver

 
 
19,500

Total first lien debt
175,000

 
 
88,821

Second lien debt:
 
 
 
 
Term loan

 
 
75,000

Paid-in-kind interest

 
 
2,318

Debt discount, net

 
 
(6,456
)
Total second lien debt, net of debt discount

 
 
70,862

Notes payable
35

 
 
3,593

Total debt
175,035

 
 
163,276

Less current portion
(6
)
 
 
(7,901
)
Long-term debt
$
175,029

 
 
$
155,375


F- 23

WESTMORELAND RESOURCE PARTNERS, LP AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(in thousands, except for unit and per unit data)

Credit Facilities Generally
In June 2013, we closed on $175 million of credit facilities that were comprised of (i) a first lien credit facility consisting of a $75 million term loan and a $25 million revolver under a first lien financing agreement (the “First Lien Financing Agreement”) and (ii) a second lien credit facility consisting of a $75 million term loan (with an option for an additional $10 million term loan if requested by us and approved by the issuing second lien lender) under a second lien financing agreement (the “Second Lien Financing Agreement,” and collectively with the First Lien Financing Agreement, the “2013 Financing Agreements”).
The first lien credit facility was scheduled to mature in September 2015 with an option to extend to June 2016, and the second lien credit facility was scheduled to mature in December 2015 with an option to extend to September 2016, in both cases if certain conditions were met.
In connection with the Second Lien Financing Agreement, certain lenders and lender affiliates (the "Warrantholders") received warrants entitling them to purchase 162,972 common units and 151,182 subordinated units at $0.12 per unit (unit and per unit amounts have been adjusted for the 12-to-1 reverse unit split effective December 31, 2014). The warrants, classified as a liability, were recorded at their fair value of $7.9 million at issuance as a debt discount. The warrants are subsequently marked to fair value with the change in fair value reported in earnings. This discount was being amortized through interest expense over the life of our second lien credit facility using the effective interest method. For the years ended December 31, 2014 and 2013, amortization of the debt discount totaled $3.0 million and $1.5 million, respectively.
All subordinated unit warrants were canceled on January 1, 2015 in connection with the WCC transactions. Accelerated vesting of LTIP units just prior to the WCC transactions triggered anti-dilution provisions in the common warrant agreement and 3,585 additional post-split warrants were issued.
On December 31, 2014, we closed on 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. 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 new credit facility matures in December 2018. The 2014 Financing Agreement contains customary financial and other covenants. 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.
As of December 31, 2014, we had a term loan of $175 million outstanding under the 2014 Financing Agreement. Borrowings on such term loan bears interest at a variable rate per annum equal to, at our option, the London Interbank Offered Rate (as defined in the 2014 Financing Agreement) (“LIBOR”) (floor of 0.75% plus 8.5%) or the Reference Rate (as defined in the 2014 Financing Agreement). As of December 31, 2014, the 2014 Financing Agreement had a cash interest rate of 9.25%, consisting of the LIBOR floor (0.75%) plus 8.5%.
The 2014 Financing Agreement also provides for “PIK Interest” (paid-in-kind interest as defined in the 2014 Financing Agreement) at a variable rate per annum between 1.00% and 3.00% based on our total net leverage ratio (as defined in the 2014 Financing Agreement). The rate of PIK Interest is recalculated on a quarterly basis with the PIK Interest added quarterly to the then-outstanding principal amount of the term loan under the 2014 Financing Agreement. PIK Interest under the 2014 Financing Agreement was inconsequential for the year ended December 31, 2014.
As a result of our refinancing with the 2014 Financing Agreement, we recorded a $1.6 million loss on extinguishment of debt in the year ended December 31, 2014 as it pertains to cost associated with repayment of the debt under the 2013 Financing Agreements.
As of December 31, 2014, we were in compliance with all covenants under the terms of the 2014 Financing Agreement.
2013 Financing Agreements
Under the 2013 Financing Agreements, we were required to make quarterly principal payments of $1.3 million on the first lien credit facility and $0.2 million on the second lien credit facility until maturity. Principal repayments totaled $15.1 million and $5.7 million for the first lien financing agreement during 2014 and 2013, respectively, including required

F- 24

WESTMORELAND RESOURCE PARTNERS, LP AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(in thousands, except for unit and per unit data)

repayment from certain proceeds we received. Principal repayments totaled $0.4 million for the second lien financing agreement during 2014 and no payments were due in 2013. The outstanding principal and accrued interest under the 2013 Financing Agreements were paid in full with proceeds from borrowings under the 2014 Financing Agreement on December 31, 2014.
Our second lien credit facility also provided for PIK Interest (paid-in-kind interest as defined in the Second Lien Financing Agreement) at the rate of 5.75%. PIK Interest is added quarterly to the then-outstanding principal amount of the term loan as additional principal obligations. For the year ended December 31, 2014 and 2013, PIK Interest related to the second lien credit facility totaled $4.6 million and $2.3 million, respectively.
Debt Maturity Table
The total debt of the Partnership matures as follows:
During the years ending December 31, 2015
$
6

2016
29

2017

2018
175,000

 
$
175,035

Deferred Financing Costs
We capitalized $7.0 million of deferred financing costs related to the 2014 Financing Agreement during the year ended December 31, 2014, and $9.6 million of deferred financing costs related to the 2013 Financing Agreements during the year ended December 31, 2013. These costs, included in Deferred financing costs, net , represent fees paid to lenders and advisors and for legal services.
Amortization of deferred financing costs included in interest expense was $4.1 million, $3.2 million and $2.2 million for the years ended December 31, 2014, 2013 and 2012, respectively.
Selling and administrative expenses for 2013 included $0.7 million of fees paid to advisors and for legal services related to refinancing our then credit facility with the 2013 Financing Agreements, and $2.4 million of fees paid to lenders and advisors and for legal services related to our failed attempt to refinance our then credit facility under the previous credit agreement. There were no such expenses during the years ended December 31, 2014 and 2012.
NOTE 12:FAIR VALUE OF FINANCIAL INSTRUMENTS 
Fair value is the price that would be received to sell an asset or paid to transfer a liability in an orderly transaction between market participants at the measurement date. We disclose the fair value of financial instruments where practicable. The carrying amounts of cash equivalents, accounts receivable and accounts payable reflected on the consolidated balance sheets approximate the fair value of these instruments due to the short duration to their maturities. Long-term debt fair value estimates are based on observed prices for securities with an active trading market when available (Level 2) and otherwise using discount rate estimates based on interest rates as of December 31, 2014 (Level 3).
The estimated fair value of our debt are as follows:
 
Westmoreland Resource Partners, LP
 
Oxford Resource Partners, LP
 
(Successor)
 
(Predecessor)
 
As of December 31, 2014
 
As of December 31, 2013
 
Carrying
Amount
 
Fair Value
 
Carrying
Amount
 
Fair Value
Fixed rate debt
$
35

 
$
33

 
$
3,593

 
$
3,386

Variable rate debt
175,000

 
175,000

 
159,683

 
159,683


F- 25

WESTMORELAND RESOURCE PARTNERS, LP AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(in thousands, except for unit and per unit data)

We utilize fair value measurement guidance that, among other things, defines fair value, requires enhanced disclosures about assets and liabilities carried at fair value and establishes a hierarchical disclosure framework based upon the quality of inputs used to measure fair value. We have elected not to measure any additional financial assets or liabilities at fair value, other than those required to be recorded at fair value. 
The financial instruments measured at fair value on a recurring basis are summarized below:
 
Westmoreland Resource Partners, LP (Successor)
 
Fair Value Measurements as of December 31, 2014
 
Quoted Prices in Active Markets for Identical Asset or Liability
 
Significant Other
Observable Inputs
 
Significant
Unobservable
Inputs
Description
(Level 1)
 
(Level 2)
 
(Level 3)
Assets:
 
 
 
 
 
Restricted investments and bond collateral
$
10,621

 
$

 
$

Liabilities:
 
 
 
 
 
Warrants

 
1,981

 

 
Oxford Resource Partners, LP (Predecessor)
 
Fair Value Measurements as of December 31, 2013
 
Quoted Prices in Active Markets for Identical Asset or Liability
 
Significant Other
Observable Inputs
 
Significant
Unobservable
Inputs
Description
(Level 1)
 
(Level 2)
 
(Level 3)
Assets:
 
 
 
 
 
Restricted investments and bond collateral
$
15,177

 
$

 
$

Liabilities:
 
 
 
 
 
Warrants

 
4,599

 

 
The warrants are fair valued at each balance sheet date using the Black-Scholes model. At December 31, 2014, the fair value of each warrant was $11.88, based on the following assumptions: spot price of $12 per unit, exercise price of $0.12 per unit, term of 3.5 years, volatility of 84% and a five-year treasury rate of 1.65%
NOTE 13:LONG-TERM INCENTIVE PLAN 
Under our LTIP, we recognize equity-based compensation expense over the vesting period of the units. These units are subject to conditions and restrictions as determined by our Compensation Committee, including continued employment or service. Historically, these units generally vested in equal annual increments over four years with accelerated vesting of the first increment in certain cases. Beginning in 2012, some of the units granted to executive officers vested based on specified performance criteria. 
For the years ended December 31, 2014, 2013 and 2012, we recognized equity-based compensation expense of $4,559, $1,441 and $1,262. These amounts are included in Cost of coal revenues and Selling and administrative expenses. The change in control related to the WCC transactions triggered accelerated vesting of the remaining unvested units and all related expenses were recognized in the Predecessor period. Therefore, no units remain unvested at December 31, 2014.  

F- 26

WESTMORELAND RESOURCE PARTNERS, LP AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(in thousands, except for unit and per unit data)

The following table summarizes additional information concerning our unvested LTIP units:
 
Units
 
Weighted
Average
Grant Date
Fair Value
Unvested balance at December 31, 2012
21,497

 
$
140.08

Granted
36,583

 
47.79

Issued
(9,657
)
 
68.93

Surrendered
(1,824
)
 
163.06

Unvested balance at December 31, 2013
46,599

 
81.47

Granted
125,363

 
14.42

Issued
(108,696
)
 
33.03

Surrendered
(63,266
)
 
32.98

Unvested balance at December 31, 2014

 

 
The value of LTIP units vested during the years ended December 31, 2014, 2013 and 2012 was $5,638, $963 and $944, respectively.


F- 27

WESTMORELAND RESOURCE PARTNERS, LP AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(in thousands, except for unit and per unit data)

NOTE 14:EARNINGS (LOSSES) PER UNIT
The computation of basic and diluted earnings (losses) per unit under the two class method for limited partner units and general partner units is presented as follows:
 
Westmoreland Resource Partners, LP
 
 
Oxford Resource Partners, LP
 
(Successor)
 
 
(Predecessor)
 
Period of
December 31,
2014
 
 
Period from
January 1, 2014
Through
December 31,
20014
 
For the Year Ended December 31,
 
 
 
 
2013
 
2012
Limited partner units
 
 
 
 
 
 
 
 
Average units outstanding:
 
 
 
 
 
 
 
 
Basic
5,671,644

 
 
2,063,983

 
1,898,040

 
1,725,996

Effect of equity-based compensation
N/A

 
 
N/A

 
N/A

 
N/A

Diluted (1)(2)
5,671,644

 
 
2,063,983

 
1,898,040

 
1,725,996

 
 
 
 
 
 
 
 
 
Net loss allocated to limited partners
 
 
 
 
 
 
 
 
Basic
$
(4,379
)
 
 
$
(22,500
)
 
$
(24,470
)
 
$
(26,273
)
Diluted
(4,379
)
 
 
(22,500
)
 
(24,470
)
 
(26,273
)
 
 
 
 
 
 
 
 
 
Net loss per limited partner unit
 
 
 
 
 
 
 
 
Basic
$
(0.72
)
 
 
$
(10.92
)
 
$
(12.84
)
 
$
(15.24
)
Diluted (1)(2)
(0.72
)
 
 
(10.92
)
 
(12.84
)
 
(15.24
)
 
 
 
 
 
 
 
 
 
General partner units
 
 
 
 
 
 
 
 
Average units outstanding:
 
 
 
 
 
 
 
 
Basic and diluted (1)(2)
35,291

 
 
35,291

 
35,302

 
35,217

 
 
 
 
 
 
 
 
 
Net loss allocated to general partner
 
 
 
 
 
 
 
 
Basic
$
(27
)
 
 
$
(385
)
 
$
(455
)
 
$
(535
)
Diluted
(27
)
 
 
(385
)
 
(455
)
 
(535
)
 
 
 
 
 
 
 
 
 
Net loss per general partner unit
 
 
 
 
 
 
 
 
Basic
$
(0.72
)
 
 
$
(10.92
)
 
$
(12.84
)
 
$
(15.24
)
Diluted (1)(2)
(0.72
)
 
 
(10.92
)
 
(12.84
)
 
(15.24
)
 
 
 
 
 
 
 
 
 
Distributions paid per unit:
 
 
 
 
 
 
 
 
Limited partners:
 
 
 
 
 
 
 
 
Common
$

 
 
$

 
$

 
$
18.1500

Subordinated

 
 

 

 
7.6500

General partner

 
 

 

 
12.9000

(1) 
Unvested LTIP units are not dilutive units for the years and periods presented herein, but could be in the future.
(2) 
Unvested LTIP units are not anti-dilutive units either. Anti-dilutive units are not used in calculating diluted average units.


F- 28

WESTMORELAND RESOURCE PARTNERS, LP AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(in thousands, except for unit and per unit data)

NOTE 15:NONCONTROLLING INTEREST
Harrison Resources, a limited liability company, was formed in March 2006 by Oxford Mining to acquire coal properties, develop mine sites and mine coal for sale to customers. Effective January 30, 2007, 49% of Harrison Resources was sold to an affiliate of CONSOL Energy, CONSOL of Ohio LLC ("Consol").
Effective October 1, 2014, Oxford Mining entered into and closed under a membership interest redemption agreement with Harrison Resources and CONSOL under which Harrison Resources redeemed all of CONSOL’s interest in Harrison Resources. 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 1.7 million tons of coal reserves already owned by Harrison Resources. Harrison Resources paid total consideration of $3.6 million in these transactions.
Harrison Resources’ revenues, which are included in our consolidated statements of operations, were $23,341, $34,100 and $34,518 for the years ended December 31, 2014, 2013 and 2012, respectively. Oxford Mining had a services agreement with Harrison Resources under which we performed mining and reclamation services for agreed-upon per ton prices. Additionally, Oxford Mining had a broker agreement with Harrison Resources under which we marketed the coal.
Harrison Resources’ cash, which is deemed to be restricted, primarily relates to funds set aside for reclamation obligations in the amount of $3,969 as of December 31, 2013. The amount of such funds is included in our consolidated balance sheets as Restricted investments and bond collateral.
Harrison Resources’ total net assets as of December 31, 2013 were $10,140. Noncontrolling interest, which represents the 49% of Harrison Resources owned by CONSOL, consisted of the following:
 
Oxford Resource Partners, LP
 
(Predecessor)
 
For the Year Ended December 31,
 
2014
 
2013
Beginning balance
$
4,969

 
$
3,744

Net (loss) income
(1,270
)
 
1,225

Additional paid in capital
(99
)
 

Redemption payment
(3,600
)
 

Ending balance
$

 
$
4,969

 
NOTE 16:WORKERS’ COMPENSATION AND BLACK LUNG
We have no liabilities under state statutes and the Federal Coal Mine Health and Safety Act of 1969, as amended, to pay black lung benefits to eligible employees, former employees and their dependents. Under the Black Lung Benefits Revenue Act of 1977, as amended in 1981, each coal mine operator must pay federal black lung benefits to claimants who are current and former employees and also make payments to a trust fund for the payment of benefits and medical expenses to claimants who last worked in the coal industry prior to January 1, 1970. The trust fund is funded by an excise tax on production of up to $1.10 per ton for deep-mined coal and up to $0.55 per ton for surface-mined coal, with neither amount to exceed 4.4% of the gross sales price for the coal. For the years ended December 31, 2014, 2013 and 2012, we recorded $2.9 million, $3.2 million and $3.6 million, respectively, in our cost of coal revenues related to this excise tax.
With regard to workers’ compensation, we are insured through state sponsored programs or an insurance carrier where there is no state sponsored program.
NOTE 17:RETIREMENT PLAN
We maintain a 401(k) plan for the benefit of our employees. For the year ended December 31, 2012, we committed to and made an employer contribution at 4% of qualified wages totaling $1.9 million. For the years ended December 31, 2014 and

F- 29

WESTMORELAND RESOURCE PARTNERS, LP AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(in thousands, except for unit and per unit data)

2013, we did not commit to make and we did not and/or are not making any discretionary employer contribution to the 401(k) plan.
NOTE 18: COMMITMENTS AND CONTINGENCIES
Coal Sales Contracts
We are committed under long-term contracts to sell coal that meets certain quality requirements at specified prices. Many of these prices are subject to cost pass-through or cost adjustment provisions that mitigate some risk from rising costs. Quantities sold under some of these contracts may vary from year to year within certain limits at the option of the customer or us. As of December 31, 2014, the remaining terms of our long-term contracts range from one to two years.
Purchase Commitments 
From time to time, we purchase coal from third parties in order to meet quality or delivery requirements under our customer contracts. We buy coal on the spot market, and the cost of that coal is dependent upon the market price and quality of the coal. We previously had a long-term purchase contract for 0.4 million tons of coal per year with a separate supplier who had asserted that the contract had terminated by its terms. We entered into a settlement agreement with the supplier in February 2013 under which the parties agreed to terminate the contract with the supplier making a one-time payment of $2.1 million to us, which payment was recorded in Non-coal revenues.
Transportation
We depend upon barge, rail and truck transportation systems to deliver coal to our customers. We have a rail transportation contract that has been amended and extended through March 31, 2015. 
401(k) Plan
The GP did not make a commitment to fund an employer contribution to our 401(k) plan for the year ended December 31, 2013, and consequently no such contribution has been or will be made. For the year ended December 31, 2014, the GP made no commitment to fund an employer contribution to our 401(k) plan and will not make any such contribution.
Surety and Performance Bonds
As of December 31, 2014, we had $34.6 million in surety bonds outstanding to secure certain reclamation obligations which were collateralized by cash deposits of $9.1 million. Such cash collateral is included in Restricted investments and bond collateral on our consolidated balance sheets and Change in restricted investments and bond collateral within investing activities on our consolidated statements of cash flow. Additionally, we had road bonds totaling $0.5 million and performance bonds totaling $2.9 million outstanding to secure contractual performance. We believe these bonds will expire without any claims or payments thereon and therefore will not have a material adverse effect on our financial position, liquidity or operations.
Legal
In July 2014, we concluded litigation, with a former customer who wrongfully terminated its coal supply agreement with us, by entering into a settlement agreement under which the former customer paid us $19.5 million to compensate us for lost profits on coal sales to it due to the termination. We believe this settlement amount substantially compensates us for the damages we incurred due to the wrongful termination.
From time to time, we are involved in various legal proceedings arising in the ordinary course of business. We accrue for such liabilities when it is probable that future costs (including legal fees and expenses) will be incurred and such costs can be reasonably estimated. Accruals are based on developments to date; management's estimates of the outcomes of these matters; our experience in contesting, litigating and settling similar matters; and any related insurance coverage. While the ultimate outcome of these proceedings cannot be predicted with certainty, we have accrued $0.5 million to resolve various claims as of December 31, 2014, of which $0.3 million, net, was accrued during 2014.

F- 30

WESTMORELAND RESOURCE PARTNERS, LP AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(in thousands, except for unit and per unit data)

Guarantees
Our GP and the Partnership guarantee certain obligations of our subsidiaries. We believe that these guarantees will expire without any liability to the guarantors, and therefore will not have a material adverse effect on our financial position, liquidity or operations.
NOTE 19:CONCENTRATION OF CREDIT RISK AND MAJOR CUSTOMERS
We have a credit policy that establishes procedures to determine creditworthiness and credit limits for customers. Generally, credit is extended based on an evaluation of the customer’s financial condition. Collateral is not generally required, unless credit cannot be established.
In 2014 and 2013, we marketed our coal principally to electric utilities, electric cooperatives, municipalities and industrial customers in Indiana, Kentucky, Michigan, Ohio, Pennsylvania and West Virginia. As of December 31, 2014 and 2013, accounts receivable from electric utilities totaled $16.3 million and $19.6 million, respectively, or 72.0% and 79.5% of total receivables, respectively. The following table shows the amount of sales to each customer (in each year where applicable, a “Major Customer”) which individually accounted for greater than 10% of sales in any of the years ended December 31, 2014, 2013 and 2012, with a portion of these sales being facilitated by coal brokers.
 
Oxford Resource Partners, LP
 
(Predecessor)
 
Revenues for the Year Ended December 31,
Customer
2014
 
2013
 
2012
 
(in millions)
American Electric Power
$
167.6

 
$
146.3

 
$
128.8

First Energy
48.7

 
69.2

 
85.8

East Kentucky Power Cooperative
42.3

 
41.4

 
56.6

The Major Customers in 2014, 2013 and 2012, in the aggregate, represented 80.2%, 74.1% and 72.6%, respectively, of our total sales in the applicable year. The Major Customers in each of 2014 and 2013, in the aggregate, represented 78.9% and 81.5% of the outstanding accounts receivable at December 31, 2014 and 2013, respectively.
NOTE 20:RELATED PARTY TRANSACTIONS
In connection with our formation in August 2007, the Partnership and Oxford Mining entered into an administrative and operational services agreement (the “Services Agreement”) with our GP. The Services Agreement is terminable by either party upon thirty days’ written notice. Under the terms of the Services Agreement, our GP provides services through its employees to us and is reimbursed for all related costs incurred on our behalf. Our GP provides us with services such as general administrative and management, human resources, legal, information technology, finance and accounting, corporate development, real property, marketing, engineering, operations (including mining operations), geological, risk management and insurance services. Pursuant to the Services Agreement, the primary reimbursements to our GP were for costs related to payroll. Reimbursable costs under the Services Agreement totaling $0.6 million were included in accounts payable as of each of December 31, 2014 and 2013, respectively.
In connection with the WCC transactions discussed in Note 1, WKFCH entered into a coal mining lease with respect to coal reserves at WCC’s Kemmerer Mine in Lincoln County, Wyoming with a subsidiary of WCC. Under this lease, we will earn a per ton royalty as these coal reserves are mined. Through the coal leasing arrangement, the mining of the Kemmerer Mine fee coal reserves will generate minimum royalty payments 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.
We sell clay and small quantities of coal to Tunnell Hill Reclamation, LLC (“Tunnell Hill”), a company that is indirectly owned by Mr. Charles Ungurean, Mr. Thomas Ungurean, and AIM. Messrs. Charles and Thomas Ungurean own C&T which owned 17.8% of the Partnership and 33.5% of our GP prior to the WCC transactions at December 31, 2014. AIM owned 35.0% of the Partnership and 65.8% of our GP prior to the WCC transactions at December 31, 2014. We also sold equipment to Tunnell Hill for $877 in 2012. Sales to Tunnell Hill were $0.6 million, $0.4 million and $0.2 million for the years ended December 31, 2014, 2013 and 2012, respectively. Additionally, we provided contracted services to Tunnell Hill totaling $0.6

F- 31

WESTMORELAND RESOURCE PARTNERS, LP AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(in thousands, except for unit and per unit data)

million in 2014, while there were no contracted services provided during 2013 and 2012. Accounts receivable from Tunnell Hill were zero and $0.1 million for the years ended December 31, 2014 and 2013, respectively.
From time to time for business purposes, we chartered the use of various airplanes from Zanesville Aviation located in Zanesville, Ohio. Additionally, C&T owns an airplane that it leases to Zanesville Aviation and Zanesville Aviation uses that airplane in providing charter services to its customers, including us at times. During the years 2014, 2013 and 2012, we paid Zanesville Aviation an aggregate of $0.02 million, $0.1 million and $0.1 million, respectively. 
NOTE 21:SEGMENT INFORMATION
We operate in one business segment. We operate surface coal mines in Northern Appalachia and, through December 2013, in the Illinois Basin and sell high-value thermal coal to utilities, industrial customers, municipalities and other coal-related entities primarily in the eastern United States. Our operating and executive management reviews and bases its decisions upon consolidated reports. Three of our operating subsidiaries extract coal utilizing surface-mining techniques and prepare it for sale to their customers. Such operating subsidiaries share customers and a particular customer may receive coal from any one of such operating subsidiaries. We also lease or sublease coal reserves to others through Oxford Mining and WKFCH in exchange for a per ton royalty rate. 
NOTE 22:SUPPLEMENTAL QUARTERLY FINANCIAL INFORMATION - (Unaudited)
A summary of our unaudited consolidated quarterly operating results in 2014 and 2013 is as follows:
 
Westmoreland Resource Partners, LP
 
(Successor)
 
2014
 
Period of December 31
 
Total
Total revenues
$

 
$

Net (loss) income from operations
(2,783
)
 
(2,783
)
Net (loss) income attributable to WMLP unitholders
(4,406
)
 
(4,406
)
Net (loss) income allocated to general partner
(28
)
 
(28
)
Net (loss) income allocated to limited partners
(4,378
)
 
(4,378
)
(Loss) income per limited partner unit:
 
 
 
Basic
$
(0.72
)
 
$
(0.72
)
Diluted
$
(0.72
)
 
$
(0.72
)

F- 32

WESTMORELAND RESOURCE PARTNERS, LP AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(in thousands, except for unit and per unit data)

 
Oxford Resource Partners, LP
 
(Predecessor)
 
For the Three Months Ended
 
 
 
 
 
March 31,
2014
 
June 30,
2014
 
Sept. 30,
2014
 
Period from October 1, 2014 through December 31,
2014
 
Period from January 1, 2014 through December 31,
2014
Total revenues
$
78,004

 
$
82,001

 
$
94,507

 
$
67,751

 
$
322,263

Net (loss) income from operations
(3,283
)
 
1,758

 
16,233

 
(12,402
)
 
2,306

Net (loss) income attributable to WMLP
 
 
 
 
 
 
 
 
 
unitholders
(10,186
)
 
(2,897
)
 
9,787

 
(19,589
)
 
(22,885
)
Net (loss) income allocated to general partner
(202
)
 
(57
)
 
193

 
(363
)
 
(429
)
Net (loss) income allocated to limited partners
(9,984
)
 
(2,840
)
 
9,594

 
(19,226
)
 
(22,456
)
(Loss) income per limited partner unit:
 
 
 
 
 
 
 
 
 
Basic
$
(4.92
)
 
$
(1.32
)
 
$
4.68

 
$
(9.24
)
 
$
(10.92
)
Diluted
$
(4.92
)
 
$
(1.32
)
 
$
4.68

 
$
(9.24
)
 
$
(10.92
)
Distributions paid per unit:
 
 
 
 
 
 
 
 
 
Limited partners:
 
 
 
 
 
 
 
 
 
Common
$

 
$

 
$

 
$

 
$

Subordinated
$

 
$

 
$

 
$

 
$

General partner
$

 
$

 
$

 
$

 
$

 
 
Oxford Resource Partners, LP
 
(Predecessor)
 
2013
 
March 31
 
June 30
 
September 30
 
December 31
 
Total
Total revenues
$
88,726

 
$
88,125

 
$
87,586

 
$
82,330

 
$
346,767

Net (loss) income from operations
(3,356
)
 
2,434

 
(1,036
)
 
(3,972
)
 
(5,930
)
Net loss attributable to WMLP unitholders
(6,547
)
 
(4,510
)
 
(5,599
)
 
(8,269
)
 
(24,925
)
Net loss allocated to general partner
(131
)
 
(89
)
 
(112
)
 
(165
)
 
(497
)
Net loss allocated to limited partners
(6,416
)
 
(4,421
)
 
(5,487
)
 
(8,104
)
 
(24,428
)
Loss per limited partner unit:
 
 
 
 
 
 
 
 
 
Basic
$
(3.72
)
 
$
(2.52
)
 
$
(2.64
)
 
$
(3.96
)
 
$
(12.84
)
Diluted
$
(3.72
)
 
$
(2.52
)
 
$
(2.64
)
 
$
(3.96
)
 
$
(12.84
)
Distributions paid per unit:
 
 
 
 
 
 
 
 
 
Limited partners:
 
 
 
 
 
 
 
 
 
Common
$

 
$

 
$

 
$

 
$

Subordinated
$

 
$

 
$

 
$

 
$

General partner
$

 
$

 
$

 
$

 
$



F- 33


SIGNATURES
 
Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned thereunto duly authorized.

Date: March 6, 2015
 
WESTMORELAND RESOURCE PARTNERS, LP
 
By: 
WESTMORELAND RESOURCES GP, LLC, its general partner  
 
 
 
 
By: 
/s/ KEITH E. ALESSI 
 
 
Keith E. Alessi
 
 
Chief Executive Officer  
 
 
(Principal Executive Officer) 
 
 
 
 
By: 
/s/ KEVIN A. PAPRZYCKI 
 
 
Kevin A. Paprzycki
 
 
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/ KEITH E. ALESSI
 
Chairman of the Board, Director, and Chief Executive Officer
(principal executive officer)

 
March 6, 2015
Keith E. Alessi
 
 
 
/s/ KEVIN A. PAPRZYCKI
 
Director, Chief Financial Officer and Treasurer
(principal financial officer)
 
March 6, 2015
Kevin A. Paprzycki
 
 
 
/s/ MICHAEL J. MEYER
 
Controller
(principal accounting officer)

 
March 6, 2015
Michael J. Meyer
 
 
 
/s/ JENNIFER S. GRAFTON
 
Director and Chief Legal Officer
 
March 6, 2015
                 Jennifer S. Grafton
 
 
 
/s/ ROBERT T. CLUTTERBUCK
 
Director
 
March 6, 2015
Robert T. Clutterbuck
 
 
 
/s/ KEITH D. HORTON
 
Director
 
March 6, 2015
Keith D. Horton
 
 
 
/s/ KURT D. KOST
 
Director
 
March 6, 2015
Kurt D. Kost
 
 
 
/s/ GERALD A. TYWONIUK
 
Director
 
March 6, 2015
Gerald A. Tywoniuk
 
 
 
/s/ CHARLES C. UNGUREAN
 
Director
 
March 6, 2015
Charles C. Ungurean
 
 
 


91

 

WESTMORELAND RESOURCE PARTNERS, LP AND SUBSIDIARIES

.


Index to Exhibits
Exhibit
Number
 
Description
3.1
 
Certificate of Limited Partnership of Westmoreland Resource Partners, LP (incorporated by reference to Exhibit 3.1 to the Registration Statement on Form S-1 (Commission File No. 333-165662) filed on March 24, 2010)
 
 
 
3.1A*
 
Certificate of Amendment to Certificate of Limited Partnership of Westmoreland Resource Partners, LP executed as of December 23, 2014 to be effective December 30, 2014
 
 
 
3.2*
 
Fourth Amended and Restated Agreement of Limited Partnership of Westmoreland Resource Partners, LP dated December 31, 2014
 
 
 
3.3
 
Certificate of Formation of Westmoreland Resources GP, LLC (incorporated by reference to Exhibit 3.3 to Amendment No. 1 to the Registration Statement on Form S-1 (Commission File No. 333-165662) filed on April 21, 2010)
 
 
 
3.3A*
 
Certificate of Amendment to Certificate of Formation of Westmoreland Resources GP, LLC executed as of December 23, 2014 to be effective December 30, 2014
 
 
 
3.4
 
Third Amended and Restated Limited Liability Company Agreement of Westmoreland Resources GP, LLC dated January 1, 2012 (incorporated by reference to Exhibit 3.2 to the Current Report on Form 8-K (Commission File No. 001-34815) filed on January 4, 2011)
 
 
 
3.4A
 
First Amendment to Third Amended and Restated Limited Liability Company Agreement of Westmoreland Resources GP, LLC dated June 24, 2013 (incorporated by reference to Exhibit 3.2 to the Current Report on Form 8-K (Commission File No. 001-34815) filed on June 25, 2013)
 
 
 
3.4B
 
First Amendment to Third Amended and Restated Limited Liability Company Agreement of Westmoreland Resources GP, LLC executed as of March 12, 2014 to be effective as of June 24, 2013, entered into to correct, clarify, supersede and replace in its entirety the First Amendment to Third Amended and Restated Limited Liability Company Agreement of Westmoreland Resources GP, LLC dated June 24, 2013 (incorporated by reference to Exhibit 3.4B to the Quarterly Report on Form 10-Q (Commission File No. 001-34815) for the quarter ended March 31, 2014 filed on May 6, 2014)
 
 
 
10.2
 
Investors’ Rights Agreement, dated August 24, 2007, by and among Westmoreland Resource Partners, LP, Westmoreland Resources GP, LLC, AIM Oxford Holdings, LLC, C&T Coal, Inc., Charles C. Ungurean and Thomas T. Ungurean (incorporated by reference to Amendment No. 3 to the Registration Statement on Form S-1 (Commission File No. 333-165662) filed on June 9, 2010)
 
 
 
10.2A
 
Amendment to Investors’ Rights Agreement dated June 24, 2013 by and among Westmoreland Resource Partners, LP, Westmoreland Resources GP, LLC, AIM Oxford Holdings, LLC, C&T Coal, Inc., Charles C. Ungurean and Thomas T. Ungurean (incorporated by reference to Exhibit 10.2A to the Quarterly Report on Form 10-Q (Commission File No. 001-34815) for the quarter ended June 30, 2013 filed on August 6, 2013)
 
 
 
10.4D#
 
Employment Agreement between Westmoreland Resources GP, LLC and Gregory J. Honish, which Employment Agreement was effective on March 29, 2013 (incorporated by reference to Exhibit 10.4D to the Annual Report on Form 10-K (Commission File No. 001-34815) for the year ended December 31, 2012 filed on April 1, 2013)
 
 
 
10.4E#
 
Amendment to Employment Agreement between Westmoreland Resources GP, LLC and Gregory J. Honish, which Amendment was effective on March 3, 2014 (incorporated by reference to Exhibit 10.4E to the Annual Report on Form 10-K (Commission File No. 001-34815) for the year ended December 31, 2013 filed on March 4, 2014)
 
 
 
10.5D#
 
Employment Agreement between Westmoreland Resources GP, LLC and Daniel M. Maher, which Employment Agreement was effective on March 29, 2013 (incorporated by reference to Exhibit 10.5D to the Annual Report on Form 10-K (Commission File No. 001-34815) for the year ended December 31, 2012 filed on April 1, 2013)
 
 
 
10.5E#
 
Amendment to Employment Agreement between Westmoreland Resources GP, LLC and Daniel M. Maher, which Amendment was effective on March 3, 2014(incorporated by reference to Exhibit 10.5E to the Annual Report on Form 10-K (Commission File No. 001-34815) for the year ended December 31, 2013 filed on March 4, 2014)

92

 

WESTMORELAND RESOURCE PARTNERS, LP AND SUBSIDIARIES

.


Exhibit
Number
 
Description
10.6D#
 
Employment Agreement between Westmoreland Resources GP, LLC and Charles C. Ungurean, which Employment Agreement was effective on June 24, 2013 (incorporated by reference to Exhibit 10.6D to the Quarterly Report on Form 10-Q (Commission File No. 001-34815) for the quarter ended June 30, 2013 filed on August 6, 2013)
 
 
 
10.9#
 
Employee Unitholder Agreement among Westmoreland Resource Partners, LP, Westmoreland Resources GP, LLC and Gregory J. Honish (incorporated by reference to Amendment No. 1 to the Registration Statement on Form S-1 (Commission File No. 333-165662) filed on April 21, 2010)
 
 
 
10.10#
 
Westmoreland Resource Partners, LP Amended and Restated Long-Term Incentive Plan dated July 19, 2010 (incorporated by reference to Exhibit 10.3 to the Current Report on Form 8-K (Commission File No. 001-34815) filed on July 19, 2010)
 
 
 
10.10A#
 
First Amendment to Westmoreland Resource Partners, LP Amended and Restated Long-Term Incentive Plan effective December 31, 2013 (incorporated by reference to Annex A to the Information Statement on Schedule 14C (Commission File No. 001-34815) filed on February 4, 2014)
 
 
 
10.11A#
 
Form of Long-Term Incentive Plan Award Agreement for Grant of Phantom Units for general use (incorporated by reference to Exhibit 10.11A to the Annual Report on Form 10-K (Commission File No. 001-34815) for the year ended December 31, 2011 filed on March 14, 2012)
 
 
 
10.11B#
 
Form of Long-Term Incentive Plan Award Agreement for Grant of Phantom Units for use with Charles C. Ungurean, Bradley W. Harris, Gregory J. Honish and Daniel M. Maher (incorporated by reference to Exhibit 10.11B to the Annual Report on Form 10-K (Commission File No. 001-34815) for the year ended December 31, 2011 filed on March 14, 2012)
 
 
 
10.12#
 
Non-Employee Director Compensation Plan adopted on June 28, 2011 and effective on January 1, 2011 (incorporated by reference to Exhibit 10.12 to the Annual Report on Form 10-K (Commission File No. 001-34815) for the year ended December 31, 2011 filed on March 14, 2012)
 
 
 
10.12A#
 
Non-Employee Director Compensation Plan adopted on February 28, 2013 and effective on January 1, 2013 (incorporated by reference to Exhibit 10.12A to the Annual Report on Form 10-K (Commission File No. 001-34815) for the year ended December 31, 2012 filed on April 1, 2013)
 
 
 
10.13#
 
Form of Non-Employee Director Compensation Plan Award Agreement for Grant of Unrestricted Units (incorporated by reference to Exhibit 10.13 to the Annual Report on Form 10-K (Commission File No. 001-34815) for the year ended December 31, 2011 filed on March 14, 2012)
 
 
 
10.14#
 
Director Unitholder Agreement, dated December 1, 2009, by and among Westmoreland Resource Partners, LP, Westmoreland Resources GP, LLC and Gerald A. Tywoniuk (incorporated by reference to Amendment No. 1 to the Registration Statement on Form S-1 (Commission File No. 333-165662) filed on April 21, 2010)
 
 
 
10.15
 
Acquisition Agreement, dated August 14, 2009, by and among Oxford Mining Company, LLC, Phoenix Coal Inc., Phoenix Coal Corporation and Phoenix Newco, LLC (incorporated by reference to Amendment No. 1 to the Registration Statement on Form S-1 (Commission File No. 333-165662) filed on April 21, 2010)
 
 
 
10.16A
 
Coal Purchase and Sale Agreement No. 10-62-04-900, dated May 21, 2004, by and between Oxford Mining Company, Inc. and American Electric Power Service Corporation, agent for Columbus Southern Power Company (incorporated by reference to Amendment No. 4 to the Registration Statement on Form S-1 (Commission File No. 333-165662) filed on June 25, 2010)
 
 
 
10.16B
 
Amendment No. 2004-1 to Coal Purchase and Sale Agreement, dated October 25, 2004 (incorporated by reference to Amendment No. 1 to the Registration Statement on Form S-1 (Commission File No. 333-165662) filed on April 21, 2010)
 
 
 
10.16C
 
Amendment No. 2005-1 to Coal Purchase and Sale Agreement, dated April 8, 2005 (incorporated by reference to Amendment No. 4 to the Registration Statement on Form S-1 (Commission File No. 333-165662) filed on June 25, 2010)


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WESTMORELAND RESOURCE PARTNERS, LP AND SUBSIDIARIES

.


Exhibit
Number
 
Description
10.16D
 
Amendment No. 2006-3 to Coal Purchase and Sale Agreement, dated December 5, 2006 (incorporated by reference to Amendment No. 4 to the Registration Statement on Form S-1 (Commission File No. 333-165662) filed on June 25, 2010)
 
 
 
10.16E
 
Amendment No. 2008-6 to Coal Purchase and Sale Agreement, dated December 29, 2008 (incorporated by reference to Amendment No. 4 to the Registration Statement on Form S-1 (Commission File No. 333-165662) filed on June 25, 2010)
 
 
 
10.16F
 
Amendment No. 2009-1 to Coal Purchase and Sale Agreement, dated May 21, 2009 (incorporated by reference to Amendment No. 4 to the Registration Statement on Form S-1 (Commission File No. 333-165662) filed on June 25, 2010)
 
 
 
10.16G
 
Amendment No. 2009-3 to Coal Purchase and Sale Agreement, dated December 15, 2009 (incorporated by reference to Amendment No. 4 to the Registration Statement on Form S-1 (Commission File No. 333-165662) filed on June 25, 2010)
 
 
 
10.16H
 
Amendment No. 2010-1 to Coal Purchase and Sale Agreement, dated January 11, 2010 (incorporated by reference to Amendment No. 4 to the Registration Statement on Form S-1 (Commission File No. 333-165662) filed on June 25, 2010)
 
 
 
10.16I
 
Amendment No. 2010-2 to Coal Purchase and Sale Agreement, dated February 4, 2010 (incorporated by reference to Amendment No. 1 to the Registration Statement on Form S-1 (Commission File No. 333-165662) filed on April 21, 2010)
 
 
 
10.16J
 
Amendment No. 2010-3 to Coal Purchase and Sale Agreement, dated April 16, 2010 (incorporated by reference to Amendment No. 3 to the Registration Statement on Form S-1 (Commission File No. 333-165662) filed on June 9, 2010)
 
 
 
10.16K
 
Amendment No. 2011-5 to Coal Purchase and Sale Agreement, dated October 26, 2011 (incorporated by reference to Exhibit 10.16K to the Annual Report on Form 10-K (Commission File No. 001-34815) for the year ended December 31, 2011 filed on March 14, 2012)
 
 
 
10.16L
 
Amendment No. 2012-1 to Coal Purchase and Sale Agreement, dated March 21, 2012 (incorporated by reference to Exhibit 10.16L to the Quarterly Report on Form 10-Q (Commission File No. 001-34815) for the quarter ended March 31, 2012 filed on May 9, 2012)
 
 
 
10.16M
 
Amendment No. 2012-2 to Coal Purchase and Sale Agreement, dated July 30, 2012 (incorporated by reference to Exhibit 10.16M to the Quarterly Report on Form 10-Q (Commission File No. 001-34815) for the quarter ended September 30, 2012 filed on November 7, 2012)
 
 
 
10.16N
 
Amendment No. 2013-2 to Coal Purchase and Sale Agreement, dated February 6, 2013 (incorporated by reference to Exhibit 10.16N to the Annual Report on Form 10-K (Commission File No. 001-34815) for the year ended December 31, 2012 filed on April 1, 2013)
 
 
 
10.16O
 
Amendment No. 2013-5 to Coal Purchase and Sale Agreement, dated June 26, 2013 (incorporated by reference to Exhibit 10.16O to the Quarterly Report on Form 10-Q (Commission File No. 001-34815) for the quarter ended June 30, 2013 filed on August 6, 2013)
 
 
 
10.16P
 
Amendment No. 2014-1 to Coal Purchase and Sale Agreement, dated January 6, 2014 (incorporated by reference to Exhibit 10.16P to the Annual Report on Form 10-K (Commission File No. 001-34815) for the year ended December 31, 2013 filed on March 4, 2014)
 
 
 
10.16Q
 
Amendment No. 2014-2 to Coal Purchase and Sale Agreement, dated February 27, 2014 (incorporated by reference to Exhibit 10.16Q to the Annual Report on Form 10-K (Commission File No. 001-34815) for the year ended December 31, 2013 filed on March 4, 2014)
 
 
 
10.16R*
 
Amendment No. 2015-1 to Coal Purchase and Sale Agreement, dated February 26, 2015

94

 

WESTMORELAND RESOURCE PARTNERS, LP AND SUBSIDIARIES

.


Exhibit
Number
 
Description
10.17
 
Non-Compete Agreement by and among Westmoreland Resource Partners, LP, C&T Coal, Inc., Charles C. Ungurean, Thomas T. Ungurean and Westmoreland Resources GP, LLC (incorporated by reference to Amendment No. 3 to the Registration Statement on Form S-1 (Commission File No. 333-165662) filed on June 9, 2010)
 
 
 
10.18
 
Administrative and Operational Services Agreement, dated August 24, 2007, by and among Westmoreland Resource Partners, LP, Oxford Mining Company, LLC and Westmoreland Resources GP, LLC (incorporated by reference to Amendment No. 1 to the Registration Statement on Form S-1 (Commission File No. 333-165662) filed on April 21, 2010)
 
 
 
10.19
 
Employment Agreement between Westmoreland Resources GP, LLC and Bradley W. Harris (incorporated by reference to Exhibit 10.19 to the Quarterly Report on Form 10-Q (Commission File No. 001-34815) for the quarter ended September 30, 2012 filed on November 7, 2012)
 
 
 
10.19A#
 
Amendment to Employment Agreement between Westmoreland Resources GP, LLC and Bradley W. Harris dated as of March 3, 2014(incorporated by reference to Exhibit 10.19A to the Annual Report on Form 10-K (Commission File No. 001-34815) for the year ended December 31, 2013 filed on March 4, 2014)
 
 
 
10.20B#
 
Employment Agreement between Westmoreland Resources GP, LLC and Michael B. Gardner, which Employment Agreement was effective on March 29, 2013 (incorporated by reference to Exhibit 10.20B to the Annual Report on Form 10-K (Commission File No. 001-34815) for the year ended December 31, 2012 filed on April 1, 2013)
 
 
 
10.20C#
 
Amendment to Employment Agreement between Westmoreland Resources GP, LLC and Michael B. Gardner dated as of March 3, 2014 (incorporated by reference to Exhibit 10.20C to the Annual Report on Form 10-K (Commission File No. 001-34815) for the year ended December 31, 2013 filed on March 4, 2014)
 
 
 
10.21#
 
Retention bonus letter agreement between Westmoreland Resources GP, LLC and Bradley W. Harris dated as of March 29, 2013 (incorporated by reference to Exhibit 10.21 to the Annual Report on Form 10-K (Commission File No. 001-34815) for the year ended December 31, 2012 filed on April 1, 2013)
 
 
 
10.22#
 
Retention bonus letter agreement between Westmoreland Resources GP, LLC and Daniel M. Maher dated as of March 29, 2013 (incorporated by reference to Exhibit 10.22 to the Annual Report on Form 10-K (Commission File No. 001-34815) for the year ended December 31, 2012 filed on April 1, 2013)
 
 
 
10.23#
 
Retention bonus letter agreement between Westmoreland Resources GP, LLC and Gregory J. Honish dated as of March 29, 2013 (incorporated by reference to Exhibit 10.23 to the Annual Report on Form 10-K (Commission File No. 001-34815) for the year ended December 31, 2012 filed on April 1, 2013)
 
 
 
10.24
 
Financing Agreement, dated as of June 24, 2013, by and among Oxford Mining Company, LLC, as borrower, Westmoreland Resource Partners, LP, as a guarantor, the other guarantors party thereto, the lenders party thereto, and Cerberus Business Finance, LLC, as collateral agent and administrative agent for such lenders (incorporated by reference to Exhibit 10.24 to the Quarterly Report on Form 10-Q (Commission File No. 001-34815) for the quarter ended June 30, 2013 filed on August 6, 2013)
 
 
 
10.25
 
Financing Agreement, dated as of June 24, 2013, by and among Oxford Mining Company, LLC, as borrower, Westmoreland Resource Partners, LP, as a guarantor, the other guarantors party thereto, the lenders party thereto, and Obsidian Agency Services, Inc., as collateral agent and administrative agent for such lenders (incorporated by reference to Exhibit 10.25 to the Quarterly Report on Form 10-Q (Commission File No. 001-34815) for the quarter ended June 30, 2013 filed on August 6, 2013)
 
 
 
10.26
 
Intercreditor Agreement dated June 24, 2013 (incorporated by reference to Exhibit 10.26 to the Quarterly Report on Form 10-Q (Commission File No. 001-34815) for the quarter ended June 30, 2013 filed on August 6, 2013)
 
 
 
10.27
 
Warrant Issuance Agreement dated June 24, 2013 (incorporated by reference to Exhibit 10.27 to the Quarterly Report on Form 10-Q (Commission File No. 001-34815) for the quarter ended June 30, 2013 filed on August 6, 2013)

95

 

WESTMORELAND RESOURCE PARTNERS, LP AND SUBSIDIARIES

.


Exhibit
Number
 
Description
10.28
 
Form of Warrant (to purchase common units of Westmoreland Resource Partners, LP) issued pursuant to the Warrant Issuance Agreement dated June 24, 2013 (incorporated by reference to Exhibit 10.28 to the Quarterly Report on Form 10-Q (Commission File No. 001-34815) for the quarter ended June 30, 2013 filed on August 6, 2013)
 
 
 
10.29
 
Form of Warrant (to purchase subordinated units of Westmoreland Resource Partners, LP) issued pursuant to the Warrant Issuance Agreement dated June 24, 2013 (incorporated by reference to Exhibit 10.29 to the Quarterly Report on Form 10-Q (Commission File No. 001-34815) for the quarter ended June 30, 2013 filed on August 6, 2013)
 
 
 
10.29A
 
Form of Warrant (to purchase subordinated units of Westmoreland Resource Partners, LP) executed as of March 12, 2014 to be effective as of June 24, 2013, issued to correct, clarify, supersede and replace in its entirety the Warrant (to purchase subordinated units of Westmoreland Resource Partners, LP) issued pursuant to the Warrant Issuance Agreement dated June 24, 2013 (incorporated by reference to Exhibit 10.29A to the Quarterly Report on Form 10-Q (Commission File No. 001-34815) for the quarter ended March 31, 2014 filed on May 6, 2014)
 
 
 
10.30
 
Form of Warrant (to purchase Class B Units of Westmoreland Resources GP, LLC) issued pursuant to the Warrant Issuance Agreement dated June 24, 2013 (incorporated by reference to Exhibit 10.30 to the Quarterly Report on Form 10-Q (Commission File No. 001-34815) for the quarter ended June 30, 2013 filed on August 6, 2013)
 
 
 
10.31
 
Investors’ Rights Agreement, dated as of June 24, 2013, by and among Westmoreland Resource Partners, LP, Westmoreland Resources GP, LLC, AIM Oxford Holdings, LLC, and the lenders party to the Financing Agreement, dated as of June 24, 2013, by and among Oxford Mining Company, LLC, as borrower, Westmoreland Resource Partners, LP, as a guarantor, the other guarantors party thereto, such lenders, and Obsidian Agency Services, Inc., as collateral agent and administrative agent for such lenders (incorporated by reference to Exhibit 10.31 to the Quarterly Report on Form 10-Q (Commission File No. 001-34815) for the quarter ended June 30, 2013 filed on August 6, 2013)
 
 
 
10.32
 
Mediation Settlement Agreement dated July 15, 2014 between Oxford Mining Company - Kentucky, LLC and Big Rivers Electric Corporation (incorporated by reference to Exhibit 10.32 to the Quarterly Report on Form 10-Q (Commission File No. 001-34815) for the quarter ended June 30, 2014 filed on August 5, 2014)
 
 
 
10.33
 
Settlement Agreement effective July 15, 2014 between Oxford Mining Company - Kentucky, LLC and Big Rivers Electric Corporation, supplementing the Mediation Settlement Agreement dated July 15, 2014 between them (incorporated by reference to Exhibit 10.33 to the Quarterly Report on Form 10-Q (Commission File No. 001-34815) for the quarter ended June 30, 2014 filed on August 5, 2014)
 
 
 
10.34
 
Contribution Agreement, dated as of October 16, 2014, between Westmoreland Resource Partners, LP and Westmoreland Coal Company (incorporated by reference to Annex B of the Preliminary Proxy Statement filed on October 24, 2014)
 
 
 
10.35
 
Membership Interests Redemption Agreement, effective as of October 1, 2014, among Oxford Mining Company, LLC, Harrison Resources, LLC and CONSOL of Ohio LLC (incorporated by reference to Exhibit 10.35 to the Quarterly Report on Form 10-Q (Commission File No. 001-34815) for the quarter ended September 30, 2014 filed on October 30, 2014)
 
 
 
10.36
 
Financing Agreement, dated as of December 31, 2014, by and among Oxford Mining Company, LLC, Westmoreland Resource Partners, LP and each of its other subsidiaries, the lenders party thereto and U.S. Bank National Association (incorporated by reference to Exhibit 10.1 to the Current Report on Form 8K filed on January 7, 2015)
 
 
 
21.1*
 
List of Subsidiaries of Westmoreland Resource Partners, LP
 
 
 
23.1*
 
Consent of Grant Thornton LLP
 
 
 
23.2*
 
Consent of John T. Boyd Company

96

 

WESTMORELAND RESOURCE PARTNERS, LP AND SUBSIDIARIES

.


Exhibit
Number
 
Description
31.1*
 
Certification of Keith E. Alessi, Chief Executive Officer of Westmoreland Resources GP, LLC, the general partner of Westmoreland Resource Partners, LP, for the December 31, 2014 Annual Report on Form 10-K, pursuant to Section 302 of the Sarbanes-Oxley Act of 2002
 
 
 
31.2*
 
Certification of Kevin A. Paprzycki, Chief Financial Officer and Treasurer of Westmoreland Resources GP, LLC, the general partner of Westmoreland Resource Partners, LP, for the December 31, 2014 Annual Report on Form 10-K, pursuant to Section 302 of the Sarbanes-Oxley Act of 2002
 
 
 
32*
 
Certification of Keith E. Alessi, Chief Executive Officer of Westmoreland Resources GP, LLC, the general partner of Westmoreland Resource Partners, LP, and Kevin A. Paprzycki, Chief Financial Officer and Treasurer of Westmoreland Resources GP, LLC, the general partner of Westmoreland Resource Partners, LP, for the December 31, 2014 Annual Report on Form 10-K, pursuant to Section 906 of the Sarbanes-Oxley Act of 2002
 
 
 
95*
 
Mine Safety Disclosure
 
 
 
101*
 
Interactive data files pursuant to Rule 405 of Regulation S-T: (i) our Consolidated Balance Sheets as of December 31, 2014 and December 31, 2013; (ii) our Consolidated Statements of Operations for the years ended December 31, 2014, December 31, 2013 and December 31, 2012; (iii) our Consolidated Statements of Cash Flows for the years ended December 31, 2014, December 31, 2013 and December 31, 2012; (iv) our Consolidated Statements of Partners’ Capital (Deficit) for the years ended December 31, 2014, December 31, 2013 and December 31, 2012; and (v) the notes to our Consolidated Financial Statements (this information is furnished and not filed or part of a registration statement or prospectus for purposes of Sections 11 and 12 of the Securities Act of 1933, as amended, and Section 18 of the Securities Exchange Act of 1934, as amended)
 
 
 
*
 
Filed herewith (or furnished in the case of Exhibits 32.1, 32.2 and 101).
 
 
 
#
 
Compensatory plan or arrangement.
 
 
 
 
Certain portions have been omitted pursuant to a confidential treatment request. Omitted information has been filed separately with the Securities and Exchange Commission.

97