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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

.


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

.


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
)