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EX-23.2 - EXHIBIT 23.2 - Westmoreland Resource Partners, LPexhibit232-gtconsent.htm
EX-95.1 - EXHIBIT 95.1 - Westmoreland Resource Partners, LPexhibit951-minesafety.htm
EX-21.1 - EXHIBIT 21.1 - Westmoreland Resource Partners, LPexhibit211-listingofsubsid.htm
EX-31.1 - EXHIBIT 31.1 - Westmoreland Resource Partners, LPexhibit311.htm
EX-32.1 - EXHIBIT 32.1 - Westmoreland Resource Partners, LPexhibit32.htm
EX-31.2 - EXHIBIT 31.2 - Westmoreland Resource Partners, LPexhibit312.htm
EX-23.3 - EXHIBIT 23.3 - Westmoreland Resource Partners, LPexhibit233johntboydconsent.htm
EX-23.1 - EXHIBIT 23.1 - Westmoreland Resource Partners, LPexhibit231-eyconsent.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, 2015
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 80112
(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 $10.4 million as of June 30, 2015, based on the reported closing price of the common units as reported on the New York Stock Exchange on June 30, 2015.
As of March 9, 2016, 5,733,560 common units were outstanding. The common units trade on the New York Stock Exchange under the ticker symbol “WMLP.” 

DOCUMENTS INCORPORATED BY REFERENCE: None



WESTMORELAND RESOURCE PARTNERS, LP AND SUBSIDIARIES

WESTMORELAND RESOURCE PARTNERS, LP
FORM 10-K
ANNUAL REPORT
TABLE OF CONTENTS 
Item
 
Page
 
 
 
 
 
 
 
 
1
 
1A
1B
2
3
4
 
 
 
 
 
5
6
7
7A
8
9
9A
9B
 
 
 
 
 
10
11
12
13
14
 
 
 
 
 
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WESTMORELAND RESOURCE PARTNERS, LP AND SUBSIDIARIES

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 inability to renew our mineral leases or material changes in lease royalties;
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

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WESTMORELAND RESOURCE PARTNERS, LP AND SUBSIDIARIES

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.
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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WESTMORELAND RESOURCE PARTNERS, LP AND SUBSIDIARIES

PART I
 
Introduction
This report is both our 2015 Annual Report to unitholders and our 2015 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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WESTMORELAND RESOURCE PARTNERS, LP AND SUBSIDIARIES


Item 1.Business
Overview
Westmoreland Resource Partners LP is a Delaware limited partnership listed on the New York Stock Exchange ("NYSE") under the ticker symbol "WMLP". We began doing business in 1985, in Coshocton, Ohio, as a contract-mining service to a mining division of a major oil company. In 1989, we transitioned from a contract miner into a producer of our own coal reserves. On July 19, 2010 we completed our initial public offering and moved our headquarters to Columbus, Ohio. On December 31, 2014, our general partner was acquired by Westmoreland Coal Company, a Delaware corporation (“WCC”), and our executive offices were moved to Englewood, Colorado. WCC owns 100% of our GP and, as of the date of this filing, 93.9% beneficial limited partner interest on a fully diluted basis.
Today, we are a growth-oriented, low-cost producer and marketer of high-value thermal coal to U.S. utilities and industrial users under long-term coal sales contracts. We focus on acquiring thermal coal reserves that we can efficiently mine with our large-scale equipment. Our reserves and operations are well positioned to serve our primary market area of the Midwest, Northeast and Rocky Mountain regions of the United States.
We operate in a single business segment and have seven operating subsidiaries. The following chart provides an overview of the current ownership structure of the Partnership and its subsidiaries:
1The 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. As part of the December 31, 2014 restructuring of the GP the IDR distributions were suspend for six quarters, provided that such suspension may be reduced to three quarters if, during the suspension period, additional drop-down transactions aggregating greater than $35.0 million in enterprise value are undertaken by our GP or affiliates of our GP that are reasonably expected to provide accretion to per unit common unitholder distributions.

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WESTMORELAND RESOURCE PARTNERS, LP AND SUBSIDIARIES


2015 Transactions
WCC’s Contribution of Westmoreland Kemmerer, LLC
On August 1, 2015, WCC, who owns and controls our GP, contributed 100% of the outstanding equity interests in Westmoreland Kemmerer, LLC ("WKL"), which operates the Kemmerer mine in Lincoln County, Wyoming, to the Partnership in exchange for $230 million in aggregate consideration, composed of $115 million of cash and 15,251,989 Series A Units of the Partnership (“Series A Units”) with a value of $115 million (the “Kemmerer Drop”). The Kemmerer Drop will be accounted for as a reorganization of entities under common control in accordance with the provisions of Accounting Standards Codification (“ASC”) 805-50, which requires that the transaction be presented as though it occurred at the beginning of the period, and prior years retrospectively adjusted to furnish comparative information similar to the pooling method. Accordingly, our financial statements give retrospective effect to the Kemmerer Drop for periods as of and subsequent to December 31, 2014.
Immediately prior to the Kemmerer Drop and in accordance with the Amended and Restated Contribution Agreement, dated July 31, 2015, between the Partnership and WCC (the “Contribution Agreement”) all employees of WKL were transferred to WCC. WCC assumed all liabilities associated with the transferred employees, including but not limited to all post-retirement pension, medical, other benefits and the related deferred income tax assets and liabilities, which were not contributed as part of the transaction (the “Excluded Liabilities”).
In connection with the Kemmerer Drop and the issuance of the Series A Units, the Partnership entered into an amendment (the “Amendment”) to our fourth amended and restated partnership agreement, as amended (the "Partnership Agreement"). The Amendment established the terms of the Series A Units and any additional Series A Units that may be issued in kind as a distribution (the “Series A PIK Units,” together with the Series A Units, the "Series A Convertible Units"), and provided that each Series A Convertible Unit will have the right to share in distributions from us on a pro-rata basis with the common units. All or any portion of each distribution payable in respect of the Series A Convertible Units (the “Series A Convertible Unit Distribution”) may, at our election, be paid in Series A PIK Units. To the extent any portion of the Series A Convertible Unit Distribution is paid in Series A PIK Units for any quarter, the distribution to the holders of incentive distribution rights shall be reduced by that portion of the distribution that is attributable to the payment of those Series A PIK Units, as further described in the Amendment. The Series A Convertible Units will convert into common units, on a one-for-one basis, at the earlier of the date on which we first make a regular quarterly cash distribution with respect to any quarter to holders of common units in an amount at least equal to $0.22 per common unit or upon a change of control. The Series A Convertible Units have the same voting rights as if they were outstanding common units and will vote together with the common units as a single class. In addition, the Series A Convertible Units are entitled to vote as a separate class on any matters that materially adversely affect the rights or preferences of the Series A Convertible Units in relation to other classes of partnership interests or as required by law.
Revolving Credit Facility
On October 23, 2015, WMLP and its subsidiaries entered into a loan and security agreement with the lenders party thereto and The PrivateBank and Trust Company, as administrative agent (the "Loan Agreement"), which permits borrowings up to the aggregate principal amount of $15.0 million and letters of credit in an aggregate outstanding amount of up to $10.0 million (the “Revolving Credit Facility”), which reduces availability under the Revolving Credit Facility on a dollar-for-dollar basis. At December 31, 2015, availability under the Revolving Credit Facility was $15.0 million.

Services Agreement
In March 2015, we entered into a new Services Agreement (the “Services Agreement”), effective January 1, 2015, with our GP, which was further amended in October 2015. Pursuant to the Services Agreement, the Partnership engaged the GP to continue providing administrative, engineering, operating and other services to the Partnership. Administrative services include without limitation legal, accounting, treasury, insurance administration and claims processing, risk management, health, safety and environmental, information technology, human resources, credit, payroll, internal audit and tax. Under the Services Agreement, the Partnership will pay the GP a fixed annual fee of $2.2 million in 2016 for certain administrative services, and will reimburse the GP at cost for other expenses and expenditures. The term of the Services Agreement expires on December 31, 2016, but automatically renews for successive one year periods unless terminated. The primary reimbursements to our GP under the Services Agreement for the year ended December 31, 2015 were for costs related to payroll. Reimbursable costs under the Services Agreement totaling $4.2 million and $0.6 million were included in accounts payable as of December 31, 2015 and December 31, 2014 (under the previous services agreement), respectively.

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WESTMORELAND RESOURCE PARTNERS, LP AND SUBSIDIARIES


AEP Agreement
On February 26, 2015, our subsidiary Oxford Mining Company, LLC ("Oxford Mining") and AEP Generation Resources Inc. ("AEP") entered into a coal purchase and sale agreement (the “AEP Agreement”). Under the AEP Agreement, Oxford Mining agreed to sell, and AEP agreed to purchase, certain quantities of coal from January 1, 2016 through December 31, 2018 to supply AEP’s Conesville, Ohio generating plant: 1.3 million tons during 2016; 1.2 million tons during 2017; and 0.8 million tons during 2018. In addition, pursuant to the AEP Agreement, Oxford Mining has the right of first refusal to supply up to a certain number of additional tons of coal, as needed by AEP: 0.4 million tons during 2016; 0.3 million tons during 2017; and 0.2 million tons during 2018, an increase of 31%, 25%, and 27% over contracted levels, respectively.
Operations
The following map shows our current operations:
General
We are a growth-oriented, low-cost producer and marketer of high-value thermal coal to U.S. utilities and industrial users, and are the largest producer of surface mined coal in Ohio. We focus on niche coal markets where we take advantage of customer proximity and strategically located rail and barge transportation. We market our coal primarily to large electric utilities with coal-fired, base load scrubbed power plants under long-term coal sales contracts. We focus on acquiring thermal coal reserves that we can efficiently mine with our large-scale equipment. Our reserves and operations are well positioned to serve its primary market areas of the Midwest, Northeast and Rocky Mountain regions of the United States.
For the year ended December 31, 2015, WMLP sold 8.5 million tons of coal, 94.0% of which were sold pursuant to long-term coal supply contracts and generated revenue of approximately $347.6 million related to the sale of coal. As of December 31, 2015, WMLP owned or controlled approximately 145.2 million tons of coal reserves, of which 24.3 million tons were leased or subleased to others.
Customers
Our primary customers are electric utility companies 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. In 2015, we derived approximately 76.0% of our total coal revenues from sales to three customers: American Electric Power Company, Inc. (40.9%), Pacificorp Energy, Inc. (27.2%) and Eastern Kentucky Power Cooperative (7.9%). A portion of these sales were facilitated by coal brokers.

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WESTMORELAND RESOURCE PARTNERS, LP AND SUBSIDIARIES


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, 2015, approximately 94.0% 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.
Properties
Substantially all of our properties and assets are encumbered by liens securing our and our subsidiaries’ outstanding indebtedness. In addition, borrowings under the Revolving Credit Facility are secured by first priority liens on our and our wholly owned subsidiaries accounts receivable, inventory and certain other specified assets.
We owned or controlled an estimated 145.2 million tons of total proven or probable coal reserves as of December 31, 2015. The following table provides information about mines we owned or controlled as of December 31, 2015:
 
Total
 
(Tons in thousands)
Coal reserves:1
 
Proven
128,788

Probable
16,436

Total proven and probable reserves
145,224

Permitted reserves
58,896

2015 production
8,481

1The SEC Industry Guide 7 defines reserves as that part of a mineral deposit, which could be economically and legally extracted or produced at the time of the reserve determination. Proven and probable coal reserves are defined by SEC Industry Guide 7 as follows:
Proven (Measured) Reserves - Reserves for which (a) quantity is computed from dimensions revealed in outcrops, trenches, workings or drill holes; grade and/or quality are computed from the results of detailed sampling and (b) the sites for inspection, sampling and measurement are spaced so close and the geographic character is so well defined that size, shape, depth and mineral content of reserves are well-established.
Probable (Indicated) Reserves - Reserves for which quantity and grade and/or quality are computed from information similar to that used for proven (measured) 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 (measured) reserves, is high enough to assume continuity between points of observation.

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WESTMORELAND RESOURCE PARTNERS, LP AND SUBSIDIARIES


As of December 31, 2015, we operated 16 active surface mines and managed these mines as five mining complexes located in eastern Ohio and one mine located in Wyoming. The Ohio mining facilities include two preparation plants, both of which receive, wash, blend, process and ship coal produced from our active mines. The mines use a combination of area, contour, auger and highwall mining methods using truck/shovel and truck/loader equipment along with large production dozers. We also own and operate seven augers, moving them among its mining complexes, as necessary, and two highwall miner systems. In August 2015, we completed the Kemmerer Drop from WCC. The Kemmerer mine supplies approximately 2.8 million tons per year to the adjacent Naughton Power Station via conveyor belt under an agreement that expires in December 2021. The Kemmerer mine also supplies approximately 1.7 million tons a year to various industrial customers, including Tata Chemicals North America Inc. and FMC Corporation, through long-term contracts extending to 2026. These industrial customers are supplied via both short haul rail and truck. Prices under supply agreements related to the Kemmerer mine are based upon certain actual mine costs and certain inflation/commodity indices for items such as diesel fuel.
The following table provides summary information regarding our principal mining operations as of December 31, 2015:
 
 
Manner of Transport
 
Machinery
 
Tons Sold1
 
Employees2, 3
 
Coal Seam
Mining Operation
 
 
 
2013
 
2014
 
2015
 
 
 
 
 
 
 
 
(thousands of tons)
 
 
 
 
Belmont
 
Barge & truck
 
Coal crusher and blending facility
 
995

 
403

 
644
 
51
 
Pittsburgh #8, Meigs Creek #9

Cadiz
 
Barge, rail & truck
 
3 coal crushers with truck scale, rail load-out
 
2,662

 
3,074

 
2,125
 
195
 
Pittsburgh #8, Redstone #8A,Meigs Creek #9

Kemmerer
 
Conveyor, rail & truck
 
Truck and shovel
 

 

 
4,471
 
292
 
Adaville Series
Muhlenberg4
 
N/A 4
 
N/A 4
 
243

 

 
 
N/A 4
 
N/A 4
New Lexington
 
Rail & truck
 
Coal crusher with truck scale, rail load-out
 
828

 
685

 
551
 
58
 
Lower Kittanning #5. Middle Kittanning #6

Noble
 
Barge & truck
 
Coal crusher and blending facility
 
188

 
251

 
17
 
 
Pittsburgh #8, Meigs Creek #9

Plainfield3
 
Truck
 
N/A 4
 
295

 

 
 
N/A 4
 
N/A 4
Tuscarawas
 
Truck
 
2 coal crushers with truck scales, 2 blending facilities, preparation plant
 
936

 
1,140

 
673
 
62
 
Brookville #4, Lower Kittanning #5, Middle Kittanning #6, Upper Freeport #7 Mahoning #7A

Tusky3
 
N/A 4
 
N/A 4
 

 

 
 
N/A 4
 
N/A 4
Total
 
 
 
 
 
6,147

 
5,553

 
8,481

 
658
 
 
1WMLP acquired the Kemmerer mine on August 1, 2015 from WCC.
2The total number of employees does not include 39 non-union employees located at administrative offices nor does it include 76 non-union employees located at mine support facilities in Ohio.
3The total number of employees at the Kemmerer mine include 231 employees represented by the United Mine Workers of America operating under a labor agreement that expires in 2018. Immediately prior to the Kemmerer Drop and in accordance with the Amended and Restated Contribution Agreement, dated July 31, 2015, between the Partnership and WCC (the “Contribution Agreement”) all employees of WKL were transferred to WCC. WCC assumed all liabilities associated with the transferred employees, including but not limited to all post-retirement pension, medical, other benefits and the related deferred income tax assets and liabilities, which were not contributed as part of the transaction.
4These mining complexes were inactive during 2015.
Belmont. The Belmont mining complex is located in Belmont County, Ohio, and currently consists of the Speidel and Wheeling Valley mines. As of December 31, 2015, the Belmont mining complex included 9.7 million tons of proven and probable coal reserves. Coal produced from this mining complex is primarily transported to our Bellaire river terminal on the Ohio River and then transported by barge to the customer, or by truck to our Barb Tipple facility or our Conesville preparation plant and then transported by truck to the customer. Coal produced from this mining complex is crushed and blended at the Bellaire river terminal before it is loaded onto barges for shipment to our customers on the Ohio River. This mining complex

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WESTMORELAND RESOURCE PARTNERS, LP AND SUBSIDIARIES


uses area, contour, auger and highwall miner methods of surface mining. This mining complex produced 0.6 million tons of coal for the year ended December 31, 2015.
Cadiz. The Cadiz mining complex, located principally in Harrison County, Ohio, currently consists of the Harrison Resources, Daron, Ellis and Sandy Ridge mines. As of December 31, 2015, the Cadiz mining complex included 7.2 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 2.1 million tons of coal for the year ended December 31, 2015.
Kemmerer. The Kemmerer mine is located in Lincoln County, Wyoming. As of December 31, 2015, the Kemmerer mine included 89.4 million tons of proven and probable coal reserves. Coal produced from the Kemmerer mine is either transported via conveyor belt to the adjacent Naughton Power Station or shipped via short haul rail or truck to various industrial customers. This mine utilizes dragline mining methods of surface mining. The Kemmerer mine produced 4.5 million tons of coal for the year ended December 31, 2015.
New Lexington. The New Lexington mining complex is located in Perry, Athens and Morgan Counties, Ohio, and currently consists of the Avondale and New Lexington mines. As of December 31, 2015, the New Lexington mining complex included 3.6 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 facility. 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 0.6 million tons of coal for the year ended December 31, 2015.
Noble. The Noble mining complex is located in Noble and Guernsey Counties, Ohio, and currently consists of the King-Crum mine. As of December 31, 2015, the Noble mining complex included 0.2 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 less than 0.1 million tons of coal for the year ended December 31, 2015.
Plainfield. The Plainfield mining complex is located in Muskingum, Guernsey and Coshocton Counties, Ohio, and is currently inactive. As of December 31, 2015, the Plainfield mining complex included 3.6 million tons of proven and probable coal reserves.
Tuscarawas. The Tuscarawas mining complex is located in Tuscarawas and Columbiana Counties, Ohio, and consists of the East Canton, Garrett, Hunt and Stillwater mines. As of December 31, 2015, the Tuscarawas mining complex included 5.3 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 0.7 million tons of coal for the year ended December 31, 2015.
    





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The following table provides information about the mines held by us as of December 31, 2015. This table does not include any royalty properties as they are discussed below in the “Royalty Revenues” section:
 
Belmont
 
Cadiz
 
Kemmerer5, 6
 
Muhlenberg4
 
New Lexington
 
Noble
 
Plainfield4
 
Tuscarawas
 
Tusky4
 
Total
Location
Belmont County, OH
 
Harrison County, OH
 
Lincoln County, WY
 
Muhlenber & McLean Counties, OH
 
Perry, Athens & Morgan Counties, OH
 
Noble & Guernsey Counties, OH
 
Muskingum, Guernsey & Coshocton Counties, OH
 
Tuscarawas County, OH
 
Harrison & Tuscarawa Counties, OH
 
 
Coal reserves (thousands of tons)
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Proven
9,205

 
6,275

 
80,556

 
1,227

 
3,379

 
229

 
3,622

 
5,330

 
18,965

 
128,788

Probable
531

 
931

 
8,867

 
568

 
173

 

 

 

 
5,366

 
16,436

Total Proven & Probable
9,736

 
7,206

 
89,423

 
1,795

 
3,552

 
229

 
3,622

 
5,330

 
24,331

 
145,224

Permitted Reserved (thousands of tons)
1,327

 
5,466

 
30,906

 
1,227

 
1,022

 

 
282

 
1,946

 
16,720

 
58,896

2015 production (thousands of tons)
644

 
2,125

 
4,471

 

 
551

 
17

 

 
673

 

 
8,481

Estimated life of permitted reserves1
2016
 
2018
 
End 2024
 
2020+
 
2017
 
2015
 
2017
 
2018
 
2025+
 
 
Lessor
Private parties
 
Private parties
 
Private parties & Federal Gov.
 
Private parties
 
AEP & Private parties
 
Private parties
 
Private parties
 
Private parties
 
Private parties
 
 
Lease term
Varies
 
Varies
 
Varies
 
Varies
 
Varies
 
Varies
 
Varies
 
Varies
 
Varies
 
 
Current production capacity (thousands of tons)
660

 
2,580

 
7,000

 

 
600

 

 

 
600

 

 
11,440

Coal type
Bituminous
 
Bituminous
 
Sub-bituminous
 
Bituminous
 
Bituminous
 
Bituminous
 
Bituminous
 
Bituminous
 
Bituminous
 
 
Major customers
American Electric Power & East Kentucky Power Coop
 
American Electric Power & East Kentucky Power Coop
 
PacifiCorp & various industrial customers
 
N/A 4
 
American Electric Power & East Kentucky Power Coop
 
American Electric Power & East Kentucky Power Coop
 
American Electric Power & East Kentucky Power Coop
 
American Electric Power & East Kentucky Power Coop
 
N/A 4
 
 
Delivery method
Barge & truck
 
Barge, rail & truck
 
Conveyor, rail & truck
 
N/A 4
 
Rail & truck
 
Barge & truck
 
Truck
 
Truck
 
N/A 4
 
 
Approx. heat content(BTU/lb.)2
11,779

 
11,431

 
9,919

 
11,424

 
11,551

 
11,286

 
11,711

 
11,760

 
12,900

 
 
Approx. sulfur content(%)3
4.4
%
 
2.7
%
 
0.78
%
 
3.5
%
 
4.5
%
 
5.3
%
 
4.4
%
 
3.9
%
 
2.1
%
 
 
Year current complex opened
1999

 
2000

 
1950

 
2009

 
1993

 
2006

 
1990

 
2003

 
2003

 
 
Total tons mined since inception (thousands of tons)
15,838

 
450,828

 
188,737

 
107,489

 
174,678

 
191,730

 
107,489

 
192,534

 
15,148

 
1,444,471
1Approximate year in which permitted reserves would be exhausted, based on current mine plan and production rates.
2Approximate heat content applies to the coal mined in 2015.
3Approximate sulfur content applies to the tons mined in 2015.
4Mining complex was inactive during 2015.
5The Elkol Underground Mine opened in 1950 and the Sorenson Surface Operations opened in 1963. Tons mined since inception for the Kemmerer Mine are for tons mined from 1950 through 2015.
6WMLP acquired the Kemmerer mine from WCC on August 1, 2015.

Preparation Plants, Blending Facilities and Equipment
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:

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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; or
our Bellaire river terminal on the Ohio River in Bellaire, Ohio.
Currently, we own or lease most of the equipment utilized in its mining operations and employs preventive maintenance and rebuild programs to ensure that its 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.
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, 2015, we had $34.5 million in cash deposits and restricted investments supporting $132.5 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.
Royalty Revenues
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 seven years remaining on the 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 its interest assigned to the sublessee for defined and predetermined consideration. For the year ended December 31, 2015, 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. There were no oil and gas rights sales in 2015. For the fiscal year ended December 31, 2015, we generated $0.9 million in royalty revenue from the receipt of these oil and gas royalties.
Limestone Revenues
At two of our mines, limestone is removed in order to access the underlying coal. We sells 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, 2015, WMLP produced and sold 0.7 million tons of limestone, and recognized other revenue of $2.9 million in limestone sales.
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. 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, CONSOL, Foresight Energy, Hallador Energy Company, Murray Energy Corporation, Peabody Energy Corp., Rhino Resource Partners, L.P. and various other smaller, independent producers.

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Seasonality
Our coal business has historically experienced only limited variability in its results due to the effect of seasons; however, we are impacted by seasonality due to weather patterns and our customer's annual maintenance outages which typically occur during the second quarter. In addition, our customers generally respond to seasonal variations in electricity demand based upon the number of heating degree days and cooling degree days. Due to stockpile management by our customers, our coal sales may not experience the same direct seasonal volatility; however, extended mild weather patterns can impact the demand for our coal. Our sales typically benefit from decreases in customers' stockpiles due to high electricity demand. Conversely, when these stockpiles increase, demand for our coal will typically soften. Further, our ability to deliver coal is impacted by the seasons. Because the majority of our mines are mine-mouth operations that deliver their coal production to adjacent power plants, our exposure to transportation delays or outages as a result of adverse weather conditions is limited.
Material Effects of Regulation
We are subject to extensive regulation with respect to environmental and other matters by federal, state and local authorities in the United States. Federal laws in the U.S. 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, state and local 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.
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 recent history. Most of 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 comprehensive and pervasive systems for protection of employee health and safety.
Safety is a core value of WMLP. We use a grass roots approach, encouraging and promoting our workers involvement in safety and accept input from all workers; we feel our workforce's active involvement is a pillar of our safety excellence. During 2015, we continued to maintain U.S reportable and lost time incident rates below national averages as indicated in the table below.
 
2015
 
Reportable Rate
 
Lost Time Rate
WMLP Mines
1.05

 
0.35

U.S. National Average
1.82

 
1.28

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 ("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, especially in light of significant permitting issues affecting the Northern Appalachia region. This difficulty in

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permitting also affects the availability of coal reserves at our coal mines. It is our policy to comply in all material respects with the requirements of the SMCRA and the state and regulations governing mine reclamation.
Clean Air Act and Related Regulations. The U.S. 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 Clean Air Act permitting requirements and emission control requirements relating to air pollutants, including particulate matter, which may include controlling fugitive dust. The Clean Air Act 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 August of 2015, the EPA finalized standards for greenhouse gases (GHGs) for new and modified electric generating units (EGUs) referred to as “new source performance standards” or NSPS. The final NSPS for coal-fired EGUs is set at 1,400 pounds of CO2 / megawatt hour on an average annual basis which would, with few possible exceptions, require the installation of partial carbon capture and sequestration at new or modified coal-fired EGUs. Under the CAA, new source performance standards like the GHG NSPS have binding effect from the date of the proposal, which in this case was January 8, 2014. Therefore, any new coal-fired EGU must comply with this standard, which is likely to be major obstacle to the construction and development of any new coal-fired generation capacity. Existing coal-fired generation, however, is also now subject to GHG performance standards that the EPA asserts will reduce GHG emissions from the power sector by 32% from 2005 levels by 2030. At the same time the EPA issued the GHG NSPS, the EPA finalized existing source standards for fossil-fuel fired power plants, which the EPA refers to as the Clean Power Plan. The final Clean Power Plan imposes stringent standards on existing fossil-fuel fired EGUs that reflect the EPA’s assessment of the “best system of emission reduction,” (BSER) 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 an average of 75% of net summer capacity; and (3) the substitution of coal generation with renewable energy. These existing source standards are implemented by the states, which must meet individual GHG emission “goals” beginning in 2022 with phased reductions through 2030. Each state can choose either a rate-based or a mass-based goal that reflects the mix of natural gas and coal-fired generation in the state. The final goals have a greater impact on states with substantial coal-fired generation; Wyoming and North Dakota, for example, are faced with greater than 40% emission reductions from a 2012 baseline. The states have until September of 2016 to submit plans to the EPA to implement and enforce the state-specific BSER, although two-year extensions be requested by states in an initial submittal. States and industry groups challenged the rule in the U.S. Court of Appeals for the D.C. Circuit and requested a stay pending judicial review. Although the D.C. Circuit denied the stay request, in February of 2016, the U.S. Supreme Court issued a stay of the Clean Power Plan pending judicial review of the rule, including potential review by the Supreme Court. The D.C. Circuit is reviewing the rule under an expedited briefing schedule, with oral arguments to be held in June of 2016. A number of states, including Montana and Utah, have ceased development of implementation plans, while others, including Colorado, are continuing to work on plan development. If upheld by the courts, these rules have the potential to adversely affect our revenues and profitability, although it is difficult at this stage to determine the timing and extent of any such effects, or to determine the requirements of state plans resulting from these proposals that may ultimately be promulgated and require implementation. In June 2014, the U.S. Supreme Court in UARG v. EPA struck down the EPA’s GHG permitting rules to the extent they imposed on sources a requirement to obtain an air emissions permit and comply with emissions limits solely as a result of GHG emissions. The Court upheld the EPA’s authority to impose the Best Available Control Technology (“BACT”) on large industrial sources such as power plants that are otherwise required to obtain an air emissions permit under the Prevention of Significant Deterioration program or the Title V program of the Clean Air Act. In April 2015, the U.S. Court of Appeals for the D.C. Circuit rejected motions filed by industry groups and certain states arguing that GHG permitting rules should be vacated in their entirety while the EPA undertakes a new rulemaking determining how to address the Supreme Court’s ruling. Therefore the regulatory provisions addressing GHG emissions from large industrial sources, such as fossil-fuel fired EGUs, remain in place. The EPA has not yet initiated a rulemaking to address the Supreme Court’s decision.
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, often referred to as the “Mercury Air Toxics Standards,” or “MATS Rule.” 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. The EPA agreed to reconsider the new source standards, however, and again published new source standards in April 2013. 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 of 2015, the U.S. Supreme Court reversed the U.S. Court of Appeals for the D.C. Circuit and held that the EPA had failed to properly consider costs when assessing whether to regulate fossil fuel-fired EGUs under the hazardous air pollutant provisions of the Clean Air Act, referring to the agency’s own estimate that the rule would cost power plants nearly $10 billion

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a year. The D.C. Circuit remanded the rule to the EPA to conduct a cost assessment but without vacatur, allowing the rule to remain in effect while the EPA conducts the rulemaking. On December 1, 2015, the EPA published a proposed supplemental finding that regulation of EGUs is still “appropriate and necessary” in light of the costs to regulate hazardous air pollutant emissions from the source category. The EPA indicated that it expects to issue a final finding by April 15, 2016.
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. The EPA finalized designations for the sulfur dioxide NAAQS in 2013 for a handful of counties and delayed designations for the remainder of the country. The 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. The 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. In October 2015, the EPA issued a final rule lowering the ozone standard further. While it is likely that these and any future developments resulting in stricter NAAQS will to some degree adversely affect us, it is difficult at this stage to determine the timing and extent of such effects.
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 April 2014, the U.S. Supreme Court reversed the D.C. Circuit decision that vacated the CSAPR and remanded the cases for further proceedings consistent with the Court’s opinion, which acknowledged the possibility that under certain circumstances some states may have a basis to bring a particularized, as-applied challenge to the rule. The EPA filed a motion with the D.C. Circuit to lift its stay of the CSAPR and to toll for three years all deadlines that had not already passed as of the date the stay was granted. The D.C. Circuit granted the EPA’s motion in October 2014, and scheduled oral argument on the remaining challenge to the CSAPR for March 2015. In November, 2014 the EPA issued a ministerial rule aligning the CSAPR implementation dates with the Court’s order, with phase 1 reductions beginning in January 2015, and more stringent phase 2 reductions in January 2017. In July 2015, the D.C. Circuit remanded to the EPA portions of the 2014 sulfur dioxide and ozone budgets on grounds the reductions were greater than necessary to reduce impacts on downwind states, but did not vacate any portion of the rule. The EPA has indicated that it will address these issues in future rulemakings, but that phase 1 reductions will begin in January 2015, with more stringent phase 2 reductions in January 2017 as necessary.
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. In

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2014 the D.C. Circuit upheld the EPA’s 2013 decision, based on resource constraints, 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 related emission standards.
Effect on Westmoreland Resource Partners LP. Our mines do not produce “compliance coal” for purposes of the Clean Air Act. Compliance coal is coal containing 1.2 pounds or less of sulfur dioxide per million British thermal unit, or Btu. This restricts our ability to sell coal to power plants that do not utilize sulfur dioxide emission controls and otherwise leads to a price discount based, in part, on the market price for sulfur dioxide emission allowances under the Clean Air Act.
Clean Water Act. The Clean Water Act ("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. In May 2015, the EPA and the U.S. Army Corps of Engineers jointly issued a final rule to clarify which waters and wetlands are subject to regulation under the CWA. The implementation of this rule was stayed nationwide in October 2015. 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.
Endangered Species Act. The Federal Endangered Species Act ("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.
Resource Conservation and Recovery Act. We may generate wastes, including “solid” wastes and “hazardous” wastes that are subject to the federal Resource Conservation and Recovery Act ("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 impoundments 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 internet posting requirements. The rule is largely silent on the reuse of coal ash. These changes in the management of CCR could increase both 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.
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. 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 cleaning up facilities at which such substances have been released and for natural resource damages. We have not, to our knowledge, been identified as a potentially responsible party under CERCLA, nor are we aware of any prior owners or operators of our properties that have been so identified with respect to their ownership or

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operation of those properties. We also must comply with reporting requirements under the Emergency Planning and Community Right-to-Know Act and the Toxic Substances Control Act.
 Climate Change Legislation and Regulations. Numerous proposals for federal and state legislation have been made relating to 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 for their own operations. Some states, including California, and regional groups including a number of states in the northeastern and mid-Atlantic regions of the US 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, acting under existing provisions of the Clean Air Act, has begun regulating emissions of GHG, including the enactment of GHG-related reporting and permitting rules as described above. In June of 2014, the U.S. Supreme Court overturned the EPA’s GHG permitting rules to the extent they required permits based solely on emissions of GHG. Large sources of air pollutants could still be required to install GHG emission reduction technology. Underground coal mines remain subject to the EPA’s GHG Reporting Program, which required mines to submit annual GHG emission estimates to 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 from our customers the costs related to compliance with regulatory requirements imposed on us 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.
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. The costs of these bonds have fluctuated in recent years, and the market terms of surety bonds have generally become more favorable to us. 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, 2015, we had posted an aggregate of $132.5 million in surety bonds for reclamation purposes, with approximately $34.5 million of cash and restricted investment bond collateral.

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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.westmorelandMLP.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.
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.
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.
Limestone: A rock predominantly composed of the mineral calcite (calcium carbonate (“CaCO2”)).
Metallurgical coal: The various grades of coal suitable for carbonization to make coke for steel manufacture. Its quality depends on four important criteria: volatility, which affects coke yield; the level of impurities including sulfur and ash, which affects coke quality; composition, which affects coke strength; and basic characteristics, which affect coke oven safety. Metallurgical coal typically has a particularly high Btu, but low ash and sulfur content.
Nitrogen oxide (NOx): A gas formed in high temperature environments, such as coal combustion, that is a harmful pollutant and contributes to acid rain.
Northern Appalachia: Coal producing area in Maryland, Ohio, Pennsylvania and northern West Virginia.
Overburden: Layers of earth and rock covering a coal seam, that in surface mining operations must be removed prior to coal extraction.
Preparation plant: A facility for crushing, sizing and washing coal to prepare it for use by a particular customer. The washing process has the added benefit of removing some of the coal’s sulfur content. While usually located on a mine site, one plant may serve multiple mines.
Probable coal reserves: Coal reserves for which quantity and grade and/or quality are computed from information similar to that used for proven coal reserves, but the sites for inspection, sampling and measurement are farther apart or are otherwise less adequately spaced. The degree of assurance, although lower than that for proven coal reserves, is high enough to assume continuity between points of observation.
Proven coal reserves: Coal reserves for which (i) quantity is computed from dimensions revealed in outcrops, trenches, workings or drill holes; (ii) grade and/or quality are computed from the results of detailed sampling; and (iii) the

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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).
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.


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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 13: Long-Term Debt – Credit Facilities Generally included in the notes to the consolidated financial statements included in “Item 8 - Financial Statements and Supplementary Data.”
Our 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, 2015, we had a total outstanding indebtedness of $299.2 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, 2015, we had sales commitments for 91.5% of our estimated coal production (including purchased coal to supplement our production) for the year ending December 31, 2016. 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, 2015, we derived 95.5% 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 76.0% 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 credit worthy 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 the Midwest, northeastern U.S. and Rocky Mountain regions 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, 2015. During this period, 59.6% 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. For the first eleven months of 2015, the EIA estimates that coal consumption in the electric power sector totaled 690 million tons, or 93% 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. 
Our business requires substantial capital expenditures, and we may not have access to the capital required to maintain full productive capacity at our mines.
Maintaining and expanding mines and infrastructure is capital intensive. Specifically, the exploration, permitting and development of coal reserves, mining costs, the maintenance of machinery and equipment and compliance with applicable laws and regulations require substantial capital expenditures. We must continue to invest capital to maintain or to increase our production. Decisions to increase our production levels could also affect our capital needs. We cannot assure you that we will be able to maintain our production levels or generate sufficient cash flow, or that we will have access to sufficient financing to continue our production, exploration, permitting and development activities at or above our present levels, and we may be required to defer all or a portion of our capital expenditures. As of December 31, 2015, our liquidity of $18.7 million consisted of $3.7 million of cash on hand and $15.0 million of availability under our Revolving Credit Facility. Our results of

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operations, business and financial condition, as well as our ability to pay distributions to our unitholders may be materially adversely affected if we cannot make such capital expenditures.
The amount of estimated reserve replacement capital expenditures our general partner is required to deduct from operating surplus each quarter could increase in the future, resulting in a decrease in available cash from operating surplus that could be distributed to our unitholders.
Our partnership agreement requires our general partner to deduct from operating surplus each quarter estimated reserve replacement expenditures as opposed to actual reserve replacement expenditures in order to reduce disparities in operating surplus caused by fluctuating reserve replacement costs. This amount is based on our current estimates of the amounts of expenditures we will be required to make in future years to maintain our depleting reserve base, which we believe to be reasonable. In the future, our estimated reserve replacement expenditures may be more than our actual reserve replacement expenditures, which will reduce the amount of available cash from operating surplus that we would otherwise have available for distribution to unitholders. The amount of estimated reserve replacement expenditures deducted from operating surplus is subject to review and change by the board of directors of our general partner at least once a year, subject to approval by the conflicts committee of the board of directors of our general partner (the “Conflicts Committee”).
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 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.
Because most of the coal in the vicinity of our mines is owned by the U.S. federal government, our future success and growth would be affected if we are unable to acquire or are significantly delayed in the acquisition of additional reserves through the federal competitive leasing process.
The U.S. federal government owns most of the coal in the vicinity of our mines. Accordingly, the federal competitive leasing process, which is administered by the Bureau of Land Management (“BLM”), is our primary means of acquiring additional reserves. In order to win a lease and acquire additional coal, our bid for a coal tract must meet or exceed the fair market value of the coal based on the internal estimates of the BLM, which are not published, and must also exceed any third-party bids. The BLM, however, is not required to grant a lease even if it determines that a bid meets or exceeds the fair market value estimate. Furthermore, since multiple parties are permitted to submit bids for any such federal lease, another bid may be accepted instead of our own. Over time, federal coal leases have become increasingly more competitive and expensive to obtain, and the review process to act on a lease for bid continues to lengthen. We expect this trend to continue. Any failure or delay in acquiring a coal lease, or the inability to do so on economically viable terms, could cause our production to decline, and may adversely affect our business, cash flows and results of operations, perhaps materially. In January 2016, the U.S. Department of the Interior Secretary Jewell issued an order calling for a comprehensive programmatic review under the National Environmental Policy Act of the federal coal program to ensure that the program prices the leases appropriately and takes into account impacts on the environment and public health. The Department has suspended all new coal leasing decisions pending completion of this review. The programmatic review does not affect coal reserves currently under lease. The review will look closely at how, when and where leases will occur. The review is anticipated to take at least three years to complete.
The leasing process also requires us to acquire rights to mine from certain surface owners overlying the coal before the federal government will agree to lease the coal. Surface rights are becoming increasingly more difficult and costly to acquire. Certain federal regulations provide a specific class of surface owners, also known as qualified surface owners (‘‘QSOs’’), with the ability to prohibit the BLM from leasing its coal. If a QSO owns the land overlying a coal tract, federal

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laws prohibit us from leasing the coal tract without first securing surface rights to the land, or purchasing the surface rights from the QSO. This right of QSOs allows them to exercise significant influence over negotiations to acquire surface rights and can delay the leasing process or ultimately prevent the acquisition of coal underlying their surface rights. If we are unable to successfully negotiate access rights with QSOs at a price and on terms acceptable to us, we may be unable to acquire federal coal leases on land owned by the QSO. Our profitability could be adversely affected, perhaps materially, if the prices to acquire land owned by QSOs increase.
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 drop-downs 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

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inaccuracy in our estimates related to our reserves could result in decreased profitability from lower than expected revenues or higher than expected costs.
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, provincial 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 products or reducing the prices we can obtain, and also may directly affect our own power operations. In the United States, the EPA, acting s under existing provisions of the federal Clean Air Act has promulgated 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 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. In furtherance of President Obama’s announced a Climate Action Plan announced in June 2013, the EPA issued in August 2015 final standards for GHG emissions from existing fossil-fuel fired power plants, as well as new, modified and reconstructed fossil-fuel fired power plants. The Clean Power Plan sets standards for existing sources as stringent state-specific carbon emission rates to 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. In February of 2016, however, the Supreme Court issued an order staying the Clean Power Plan pending judicial review of the rule by the U.S. Court of Appeals for the D.C. Circuit as potentially review by the Supreme Court. The D.C. Circuit issued an expedited briefing schedule for challenges to the rule, and oral argument is schedule for June of 2016. 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. For additional information, see “Business - Material Effects of Regulation” in this report.
Political opposition to the development of new coal-fired power plants, or regulatory uncertainty regarding future emissions controls, may result in fewer such plants being built, which would limit our ability to grow in the future.

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An 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 issued or renewed for new and existing mines in WMLP’s area of operations has materially impacted production in Appalachia. Section 402 National Pollutant Discharge Elimination System permits and Section 404 CWA permits are required to discharge wastewater and dredged or fill material into waters of the United States. WMLP’s 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 its 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, including the issuance in May 2015 of a final rule revising the definition of regulated waters. 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 WMLP operates. In May 2015, the EPA and the U.S. Army Corps of Engineers jointly issued a final rule to clarify which waters and wetlands are subject to regulation under the CWA. The implementation of this rule was stayed nationwide in October 2015. An inability to obtain the necessary permits to conduct WMLP’s mining operations or an inability to comply with the requirements of applicable permits could reduce WMLP’s production and cash flows, which could adversely affect its business, financial condition and/or results of operations and our cash flow.
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 $56.6 million (on a present value basis) at December 31, 2015. 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 2015, we paid approximately $3.0 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, 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.
The Kemmerer Drop added unionized employees to our workforce, and our workforce may become further unionized in the future.
Approximately 236 of Kemmerer’s 297 employees who joined our workforce in connection with the Kemmerer Drop are union employees represented by United Mine Workers of America (“UMWA”), and additional members of our workforce may become represented by unions in the future. Although the Kemmerer employees are employed at the WCC level, the exposure to unionized labor in our workforce nonetheless presents an increased risk of strikes and other labor disputes, and our ability to alter labor costs will be subject to collective bargaining, which could adversely affect stability of production and our results of operations. While the occurrence of labor strikes are generally deemed force majeure events under Kemmerer’s long-term coal supply agreements, which would thereby exempt the mine from its delivery obligations, the loss of revenue from the Kemmerer mine caused by a labor strike for even a short time could have a material adverse effect on our financial results, cash flows and ability to make distributions to our unitholders.
Congress has proposed legislation to enact a law allowing workers to choose union representation solely by signing election cards, which would eliminate the use of secret ballots to elect union representation. While the impact is uncertain, if the government enacts this proposal into law, which would make it administratively easier to unionize, it may lead to more coal mines becoming unionized. Increased unionization of our mines may 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.

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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 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

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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 issued a final rule to clarify which waters and wetlands are subject to regulation under the CWA. The implementation of the rule was stayed nationwide in October 2015. 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.
Extensive environmental laws, including existing and potential future legislation, treaties and regulatory requirements relating to air emissions other than GHGs, affect our customers and could reduce the demand for coal as a fuel source and cause coal prices and sales of our coal to materially decline.
Our customers are subject to extensive environmental regulations particularly with respect to air emissions other than GHG. Coal contains impurities, including but not limited to sulfur, mercury, chlorine and other elements or compounds, many of which are released into the air when coal is burned. The emission of these and other substances is extensively regulated at the federal, state, provincial and local level, and these regulations significantly affect our customers’ ability to use the coal we produce and, therefore, the demand for that coal. Further, increased market prices for sulfur dioxide emissions allowances and increased coal ash management costs could also favor an increased blend of the lower ash compliance coal. In such a case, the customer has the option to increase its purchases of other coal and reduce purchases of our coal or terminate our contract. A termination of the contract or a significant reduction in the amount of our coal that is purchased by the customer could have a material adverse effect on our results of operations and financial condition. The EPA intends to issue or has issued a number of significant regulations that will impose more stringent requirements relating to air, water and waste controls on electric generating units. These rules include the EPA’s final rule for CCR management, announced in December 2014, that further regulates the handling of wastes from the combustion of coal. In addition, in February 2012, the 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. In June of 2015, the U.S. Supreme Court reversed the U.S. Court of Appeals for the D.C. Circuit’s decision upholding the rule and held that the EPA had failed to properly consider costs when assessing whether to regulate fossil fuel-fired EGUs under the hazardous air pollutant provisions of the Clean Air Act. In June of 2015, the U.S. Supreme Court reversed the U.S. Court of Appeals for the D.C. Circuit and held that the EPA had failed to properly consider costs when assessing whether to regulate fossil fuel-fired EGUs under the hazardous air pollutant provisions of the Clean Air Act, referring to the agency’s own estimate that the rule would cost power plants nearly $10 billion a year. The D.C. Circuit remanded the rule to the EPA to conduct a cost assessment but without vacatur, allowing the rule to remain in effect while the EPA conducts the rulemaking. On December 1, 2015, the EPA published a proposed supplemental finding that regulation of EGUs is still “appropriate and necessary” in light of the costs to regulate hazardous air pollutant emissions from the source category. The EPA indicated that it expects to issue a final finding by April 15, 2016.
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. In November, 2014 the EPA issued a ministerial rule aligning the CSAPR implementation dates with the Court’s order, with phase 1 reductions beginning in January 2015, and more stringent phase 2 reductions in January 2017. In July 2015, the D.C. Circuit remanded to the EPA portions of the 2014 sulfur dioxide and ozone budgets on grounds the reductions were greater than necessary to reduce impacts on downwind states, but did not vacate any portion of the rule. The EPA has indicated that it will address these issues in future rulemakings, but that phase 1 reductions will begin in January 2015, with more stringent phase 2 reductions in January 2017as necessary. The In May 2014, the EPA Administrator signed a final rule that establishes requirements for cooling water intake structures for the withdrawal of cooling water by electric generating plants; the rule is anticipated to affect over 500 power plants.
Considerable uncertainty is associated with air emissions initiatives. New regulations are in the process of being developed, and many existing and potential regulatory initiatives are subject to review by federal or state agencies or the courts. Stringent air emissions limitations are either in place or are likely to be imposed in the short to medium term, and these limitations will likely require significant emissions control expenditures for many coal-fired power plants. Should the owners be forced by the EPA to install technology, such as Selective Catalytic Reduction (“SCR”) technology, the capital

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requirements could make the continued operation of the two units unsustainable. As a result, power plants may switch to other fuels that generate fewer of these emissions or may install more effective pollution control equipment that reduces the need for low-sulfur coal. Any switching of fuel sources away from coal, closure of existing coal-fired power plants, or reduced construction of new coal-fired power plants could have a material adverse effect on demand for, and prices received for, our coal. Alternatively, less stringent air emissions limitations, particularly related to sulfur, to the extent enacted, could make low-sulfur coal less attractive, which could also have a material adverse effect on the demand for, and prices received for, our coal.
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.
By purchasing a common unit, a common unitholder will become bound by the provisions of our partnership agreement, including the provisions described above.

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Our general partner and its 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 93.8% beneficial limited partner interest in us on a fully diluted bases at December 31, 2015, 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 0.2% of our common units and the owner of our general partner, WCC, owns 93.8% beneficial limited partner interest on a fully diluted basis at December 31, 2015.
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.
We must pay fees to and reimburse our general partner and its affiliates for services provided, which will reduce our cash available for distributions.
Under the Services Agreement, our general partner will continue providing administrative, engineering, operating and other services to the Partnership for a fixed annual fee of $2.2 million in 2016 for certain administrative services plus reimbursement at cost for other expenses and expenditures. The term of the Agreement expires on December 31, 2016, and automatically renews for successive one-year periods unless terminated. The reimbursement to our general partner for such

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

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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. Further, on May 5, 2015, the U.S. Treasury Department (“Treasury”) and the IRS issued proposed regulations interpreting the scope of activities that generate qualifying income under Section 7704 of the Internal Revenue Code of 1986, as amended (the “Code”). We believe that the income we currently treat as qualifying income satisfies the requirements for qualifying income under the proposed regulations. The proposed regulations, however, could be changed before they are finalized and could modify the amount of our gross income that we are able to treat as qualifying income for the purposes of the qualifying income requirement. 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: (i) eliminate current deductions, the 60-month amortization period and the 10-year amortization period for exploration and development costs relating to coal and other hard mineral fossil fuels, (ii) repeal the percentage depletion allowance with respect to coal properties, (iii) repeal capital gains treatment of coal and lignite royalties and (iv) exclude from the definition of domestic production gross receipts all gross receipts derived from the production of coal and other hard mineral fossil fuels. The passage of any legislation 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 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.

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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 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.

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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. Treasury recently adopted final 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. We are currently evaluating these regulations, which apply to certain publicly traded partnerships, including us, for taxable years beginning on or after August 3, 2015. However, these regulations do not specifically authorize the use of the proration method we have previously used. Accordingly, our counsel is unable to opine as to the validity of this method. If the IRS were to challenge our proration method, 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 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 Code 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 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.

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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
See “Part I, Item 1 - Business - Operations” for specific information about our mining operations, properties and reserves.
Item 3.Legal Proceedings
We are subject, from time-to-time, to various proceedings, lawsuits, disputes, and claims (“Actions”) arising in the ordinary course of our business. Many of these Actions raise complex factual and legal issues and are subject to uncertainties. We cannot predict with assurance the outcome of Actions brought against us. Accordingly, adverse developments, settlements, or resolutions may occur and may result in a negative impact on income in the quarter of such development, settlement, or resolution. However, we do not believe that the outcome of any current Action would have a material adverse effect on our financial results.
Item 4.Mine Safety Disclosures
On July 21, 2010, Congress enacted the Dodd-Frank Wall Street Reform and Consumer Protection Act (the "Dodd-Frank Act"). Section 1503(a) of the Dodd-Frank Act contains reporting requirements regarding mine safety. Mine safety violations or other regulatory matters, as required by Section 1503(a) of the Dodd-Frank Wall Street Reform and Consumer Protection Act and Item 104 of Regulation S-K, are included as Exhibit 95.1 to this report on Form 10-K.

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PART II
Item 5.Market for Registrant’s Common Equity, Related Unitholder Matters and Issuer Purchases of Equity Securities
The common units of Westmoreland Resource Partners, LP are trading on the NYSE under the symbol "WMLP." On March 9, 2016, the closing market price for our common units was $4.08 per unit.
As of March 9, 2016, we had outstanding 5,733,560 limited partner common units, 15,656,551 Series A Convertible limited partner common units and 35,291 general partner units. We also had outstanding warrants to purchase an aggregate of 166,557 common units. There were approximately 9 registered holders of record on March 9, 2016. 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 registered holders of record. All of the Series A Convertible Units and general partner units, for which there is no established public trading market, are held by WCC.
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 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

 
 
 
 
 
 
First Quarter 2015
$
14.36

 
$
8.42

 
Second Quarter 2015
$
12.23

 
$
8.75

 
Third Quarter 2015
$
8.94

 
$
6.06

 
Fourth Quarter 2015
$
7.60

 
$
2.63

 
Cash Distributions
On April 22, 2015, July 17, 2015, October 20, 2015 and January 22, 2016 our GP declared a cash distribution for all of our limited partner common unitholders and warrant holders of $0.20 per unit for each of the quarters ended March 31, 2015, June 30, 2015, September 30, 2015 and December 31, 2015. The distributions were paid on May 15, 2015, August 14, 2015, November 13, 2015 and February 12, 2016, respectively, to all unitholders and warrant holders of record as of the close of business on May 8, 2015, August 7, 2015, November 7, 2015 and February 5, 2016, respectively. There were no distributions paid during the year ended December 31, 2014.

Cash Distribution Policies
Our partnership agreement requires that we distribute all of our available cash quarterly. Under our partnership agreement, available cash is determined at the end of each quarter and generally defined as 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 0.2% of all quarterly distributions that we make. 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 0.2% general partner interest.

43


WESTMORELAND RESOURCE PARTNERS, LP AND SUBSIDIARIES

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 August 2015, 15,251,989 common units were issued to WCC in consideration for its contribution to us of WKL. 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 2015, 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.

44


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 Successor year ended December 31, 2015.
SELECTED FINANCIAL AND OPERATING DATA
 
Westmoreland
Resource
Partners, LP
 
 
Oxford Resource Partners, LP
 
(Successor) (1)
 
 
(Predecessor)
 
Year Ended December 31,
 
Period of
December 31,
 
 
Period from January 1 through December 31,
 
Year Ended December 31,
 
2015
 
2014
 
 
2014
 
2013
 
2012
 
2011
 
 
 
 
 
 
(in thousands)
STATEMENT OF OPERATIONS DATA:
 
 
 

 
 
 

 
 

 
 

 
 

Revenues:
$
384,700

 
$

 
 
$
322,263

 
$
346,767

 
$
373,527

 
$
400,377

Operating income (loss)
(5,212
)
 
(2,783
)
 
 
2,306

 
(5,930
)
 
(14,563
)
 
1,528

Net loss
(33,688
)
 
(4,406
)
 
 
(24,155
)
 
(23,700
)
 
(26,053
)
 
(8,329
)
Per common limited partner unit (basic and diluted)
 
 
 
 
 
 
 
 
 
 
 
 
Net loss applicable to limited partner unit
(4.62
)
 
(0.72
)
 
 
(10.92
)
 
(12.84
)
 
(15.24
)
 
(7.44
)
CONSOLIDATED BALANCE SHEET INFORMATION (end of period):
 
 
 
 
 
 
 
 
 
 
 
 
Working capital (deficit)
$
4,188

 
$
5,936

 
 
N/A
 
$
(1,452
)
 
$
(84,129
)
 
$
(4,758
)
Net property, plant and equipment
277,641

 
309,757

 
 
N/A
 
144,426

 
158,483

 
195,607

Total Assets
425,290

 
483,845

 
 
N/A
 
224,355

 
220,899

 
261,265

Total Debt
309,389

 
186,666

 
 
N/A
 
163,276

 
74,450

 
159,461

Unitholders' capital (deficit)
13,154

 
107,987

 
 
N/A
 
(15,967
)
 
73,021

 
(10,998
)
OTHER CONSOLIDATED DATA:
 
 
 
 
 
 
 
 
 
 
 
 
Net cash provided by (used in):
 
 
 
 
 
 
 
 
 
 
 
 
Operating activities
$
31,994

 
$
(1,820
)
 
 
$
24,385

 
$
9,716

 
$
31,776

 
$
43,951

Investing activities
(134,878
)
 
83

 
 
(8,253
)
 
(22,463
)
 
(8,059
)
 
(31,914
)
Financing Activities
100,590

 
7,741

 
 
(19,221
)
 
11,859

 
(22,772
)
 
3,954

Capital expenditures
20,056

 

 
 
15,903

 
22,332

 
22,687

 
33,859

Adjusted EBITDA2
66,135

 

 
 
36,296

 
39,058

 
47,917

 
58,785

Distributable cash flow3
16,402

 
(2,922
)
 
 
11,510

 
(4,119
)
 
4,913

 
3,292

Tons sold
8,481

 

 
 
5,631

 
6,602

 
7,350

 
8,458

Distributions paid per unit:
 
 
 
 
 
 
 
 
 
 
 
 
Limited partners:
 
 
 
 
 
 
 
 
 
 
 
 
Common
$
0.6000

 
$

 
 
$

 
$

 
$
1.5125

 
$
1.7500

Series A Convertible
0.2000

 

 
 

 

 

 

General partner
0.6000

 

 
 

 

 
1.0750

 
1.7500

1See Note 3: Acquisition and Pushdown Accounting included in the notes to the consolidated financial statements included in “Item 8 - Financial Statements and Supplementary Data.”
2 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."

45


WESTMORELAND RESOURCE PARTNERS, LP AND SUBSIDIARIES

3Distributable Cash Flow is not defined in GAAP. Distributable Cash Flow 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 Distributable Cash Flow and a reconciliation of Distributable Cash Flow to its most directly comparable financial measures calculated and presented in accordance with GAAP, please see “Non-GAAP Financial Measures."
Non-GAAP Financial Measures
Adjusted EBITDA
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
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.
Distributable Cash Flow
Distributable Cash Flow represents Adjusted EBITDA less cash interest expense (net of interest income), reserve replacement expenditures, maintenance capital expenditures, cash reclamation expenditures and noncontrolling interest. Cash interest expense represents the portion of our interest expense accrued and paid in cash during the reporting periods presented or that we will pay in cash in future periods as the obligations become due. Other maintenance capital expenditures represent expenditures for coal reserve replacement, and for plant, equipment and mine development. Cash reclamation expenditures represent the reduction to our reclamation and mine closure costs resulting from cash payments. Earnings attributable to the noncontrolling interest are not available for distribution to our unitholders and accordingly are deducted.
Distributable Cash Flow should not be considered as an alternative to net income (loss) attributable to our unitholders, income from operations, cash flows from operating activities or any other measure of performance presented in accordance with GAAP. Although Distributable Cash Flow is not a measure of performance calculated in accordance with GAAP, we believe Distributable Cash Flow is useful to investors because this measurement is used by many analysts and others in the industry as a performance measurement tool to evaluate our operating and financial performance, facilitating comparison with the performance of other publicly traded limited partnerships.


46


WESTMORELAND RESOURCE PARTNERS, LP AND SUBSIDIARIES

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)
 
Year Ended December 31,
 
Period of
December 31,
 
 
Period from January 1 through December 31,
 
Year Ended December 31,
 
2015
 
2014
 
 
2014
 
2013
 
2012
 
2011
 
 
 
 
 
 
(in thousands)
 
 
 
 
Reconciliation of Adjusted EBITDA to Net Loss
 
 
 
 
 
 
 
 
 
Net loss
$
(33,688
)
 
$
(4,406
)
 
 
$
(24,155
)
 
$
(23,700
)
 
$
(26,053
)
 
$
(8,329
)
Loss (gain) on extinguishment of debt

 
1,623

 
 
(500
)
 
808

 

 

Income tax expense
157

 

 
 

 

 

 

Interest expense, net of interest income
29,904

 

 
 
27,783

 
20,242

 
11,490

 
9,857

Depreciation, depletion and amortization
54,503

 

 
 
39,315

 
48,081

 
51,170

 
51,905

Accretion of ARO and receivable
5,085

 

 
 
2,337

 
2,293

 
1,567

 
3,355

EBITDA
55,961

 
(2,783
)
 
 
44,780

 
47,724

 
38,174

 
56,788

Restructuring charges
656

 
2,783

 
 
75

 
1,761

 
15,650

 

Legal settlements

 

 
 
(17,548
)
 
(2,100
)
 

 

Recapitalization costs

 

 
 
5,470

 

 

 

(Gain)/loss on sale of assets
6,890

 

 
 
14

 
(372
)
 
(1,692
)
 
1,352

Share-based compensation
438

 

 
 
4,559

 
1,441

 
1,262

 
1,077

Other non-cash and non-recurring costs
2,190

 

 
 
(1,054
)
 
(9,396
)
 
(5,477
)
 
(432
)
Adjusted EBITDA
66,135

 

 
 
36,296

 
39,058

 
47,917

 
58,785

Deferred revenue
2,513

 

 
 

 

 

 

Reclamation and mine closure costs
(8,216
)
 

 
 
(4,999
)
 
(8,666
)
 
(8,966
)
 
(5,751
)
Maintenance capital expenditures and other capitalized items
(15,763
)
 

 
 
(14,066
)
 
(18,640
)
 
(23,613
)
 
(31,969
)
Pension and postretirement medical
2,552

 

 
 

 

 

 

Cash interest expense, net of interest income
$
(20,740
)
 
$
(2,922
)
 
 
$
(15,952
)
 
$
(12,258
)
 
$
(9,461
)
 
$
(8,208
)
Legal and insurance settlement proceeds

 

 
 
17,548

 
2,100

 
600

 
1,096

Other
(10,079
)
 

 
 
(7,317
)
 
(5,713
)
 
(1,564
)
 
(10,661
)
Distributable Cash Flow
$
16,402

 
$
(2,922
)
 
 
$
11,510

 
$
(4,119
)
 
$
4,913

 
$
3,292

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.”
2Includes non-cash activity from the change in fair value of investments and warrants as well as non-recurring cost associated with the Kemmerer Drop.
3Includes payments made to pay down our Term Loan as well as capital lease payments and debt issuance costs.


47


WESTMORELAND RESOURCE PARTNERS, LP AND SUBSIDIARIES

Item 7.Management’s Discussion and Analysis of Financial Condition and Results of Operations
The following discussion and analysis contains forward-looking statements and estimates that involve risks and uncertainties. Actual results could differ materially from these estimates. Factors that could cause or contribute to differences from estimates include those discussed under “Cautionary Note Regarding Forward-Looking Statements” and “Risk Factors” contained in Item 1 above.
Overview
We are a low-cost producer and marketer of high-value thermal coal to U.S. utilities and industrial users. 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, West Virginia and Wyoming. 
We operate in a single business segment and have five operating subsidiaries, Oxford Mining Company, LLC, Oxford Mining Company-Kentucky, LLC, WKL, Westmoreland Kemmerer Fee Coal Holdings, LLC and Harrison Resources. All of our operating subsidiaries participate primarily in the business of utilizing surface mining techniques to extract coal and prepare it for sale to our customers.
One of the major factors affecting the volume of coal that we sell in any given year is the demand for coal-generated electric power, as well as the specific demand for coal by our customers. Numerous factors affect the demand for electric power and the specific demands of customers including weather patterns, the presence of hydro or wind in our particular energy grids, environmental and legal challenges, political influences, energy policies, domestic economic conditions, power plant outages and other factors discussed herein.
We sell almost all of our coal and electricity production under long-term agreements. Our long-term coal contracts typically contain price escalation and adjustment provisions, pursuant to which the price for our coal may be periodically revised in line with broad economic indicators such as the consumer price index, commodity specific indices and/or changes in our actual costs.
For our contracts that are not cost protected in nature, we have exposure to inflation and price risk for supplies used in the normal course of production such as diesel fuel and explosives. In line with the worldwide mining industry, we have experienced increased for time-to-time operating costs for mining equipment, diesel fuel and other supplies, such as tires. We manage these items through strategic sourcing contracts in normal quantities with our suppliers and may use derivatives from time-to-time.
Please see Item 1 - Business, under “Overview,” “2015 Transactions,” and “Recent Developments” information regarding the Kemmerer Drop that occurred during 2015.











48


WESTMORELAND RESOURCE PARTNERS, LP AND SUBSIDIARIES

Results of Operations 
Items that Affect Comparability of Our Results
For 2015 and each of the prior two years, our results have included items that do not relate directly to ongoing operations. The (income) expense components of these items were as follows (in thousands):
 
Westmoreland Resource Partners, LP
 
 
Oxford Resource Partners, LP
 
(Successor)
 
 
(Predecessor)
 
Year Ended December 31,
 
Period of
December 31,
 
 
Period from January 1 through December 31,
 
Year Ended December 31,
 
2015
 
2014
 
 
2014
 
2013
Items that Affect Comparability of Our Results
 
 
 
 
 
 
 
 
Acquisition and transaction costs
$
2,552

 
$

 
 
$

 
$

Restructuring and impairment charges
656

 
2,783

 
 
75

 
1,761

Loss (gain) on extinguishment of debt

 
1,623

 
 
(500
)
 
808

Recapitalization costs

 

 
 
5,470

 

Legal and insurance settlement proceeds

 

 
 
(17,548
)
 
(2,100
)
Debt issuance costs

 

 
 
(6,993
)
 
(3,109
)
Total Impact
$
3,208

 
$
4,406

 
 
$
(19,496
)
 
$
(2,640
)
Items recorded in 2015:
We incurred $2.6 million in various investment banker and legal costs related to the Kemmerer Drop.
We incurred $0.7 million in restructuring costs resulting from the right sizing of the financing and accounting team after the acquisition of our general partner by Westmoreland Coal Company in December 2014.
Items recorded in 2014 (Successor):
We incurred $2.8 million in restructuring costs resulting from termination of the executive team after the acquisition of our general partner by Westmoreland Coal Company on December 31, 2014.
We incurred $1.6 million in loss on extinguishment debt related to the payoff of the 2013 Financing Agreement.
Items recorded in 2014 (Predecessor):
We incurred $0.1 million in restructuring costs related to the idling of our Illinois Basin operations on December 31, 2013. These charges included professional and legal fees, and transportation costs associated with moving idled equipment to our Northern Appalachian operations.
We incurred a $0.5 million gain on extinguishment of debt resulting from the forgiveness of a note payable.
We incurred $5.5 million in various investment banker and legal costs associated with Westmoreland Coal Company's acquisition of our general partner on December 31, 2014.
We received $17.5 million in litigation settlement proceeds, net of legal expenses, from a former customer compensating us for lost profits on coal sales due to a wrongful termination of a coal supply agreement.
We incurred $7.0 million in debt refinancing costs related to the 2014 Financing Agreement.

49


WESTMORELAND RESOURCE PARTNERS, LP AND SUBSIDIARIES

Items recorded in 2013:
We incurred $1.8 million in restructuring costs related to the idling of our Illinois Basin operations on December 31, 2013. These charges included termination costs for employees, professional and legal fees, and transportation costs associated with moving idled equipment to our Northern Appalachian operations.
We incurred $0.8 million in loss on extinguishment debt related to the payoff of the 2010 Credit Agreement.
We received $2.1 million in settlement proceeds resulting from an agreement with a supplier in February 2013 under which the parties agreed to terminate the contract with the supplier making a one-time payment.
We incurred $3.1 million in debt refinancing costs related to the 2013 Financing Agreement.
Year Ended December 31, 2015 (Successor) Compared to Period of January 1, 2014 through December 31, 2014 (Predecessor)  
Overview
 
Westmoreland
Resource
Partners, LP
 
 
Oxford Resource Partners, LP
 
 
 
 
 
(Successor)
 
 
(Predecessor)
 
 
 
 
 
Year Ended December 31,
 
 
Period from January 1 through December 31,
 
Increase (Decrease)
 
2015
 
 
2014
 
$
 
%
Total Revenues
$
384.7

 
 
$
322.3

 
$
62.4

 
19.4
%
Net Loss
(33.7
)
 
 
(24.2
)
 
(9.5
)
 
39.3
%
Adjusted EBITDA1
66.1

 
 
36.3

 
29.8

 
82.1
%
1Adjusted 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."
Total revenue was $384.7 million for the year ended December 31, 2015, an increase of $62.4 million, or 19.4%, from $322.3 million for the predecessor period ended December 31, 2014. Net loss for the year ended December 31, 2015 was $33.7 million, compared to a net loss for the year ended December 31, 2014 of $24.2 million. Adjusted EBITDA was $66.1 million for the year ended December 31, 2015, an increase of $29.8 million from $36.3 million for the predecessor period ended December 31, 2014.

50


WESTMORELAND RESOURCE PARTNERS, LP AND SUBSIDIARIES

Coal Sales Revenues
 
Westmoreland
Resource
Partners, LP
 
 
Oxford Resource Partners, LP
 
 
 
 
 
(Successor)
 
 
(Predecessor)
 
 
 
 
 
Year Ended December 31,
 
 
Period from January 1 through December 31,
 
Increase (Decrease)
 
2015
 
 
2014
 
$
 
%
Total coal sales revenue
$
375.1

 
 
$
295.7

 
$
79.4

 
26.9
%
Coal sales revenue was $375.1 million for the year ended December 31, 2015, an increase of $79.4 million, or 26.9%, from $295.7 million for the predecessor period ended December 31, 2014. The increase was primarily attributable to a 50.6% increase in sales tons in the amount of $149.7 million that was primarily the result of the Kemmerer Drop, partially offset by a $8.27 per ton, or an aggregate $70.3 million, decrease in the average sale price per ton for the year ended December 31, 2015. 
Non-coal Revenues
 
Westmoreland
Resource
Partners, LP
 
 
Oxford Resource Partners, LP
 
 
 
 
 
(Successor)
 
 
(Predecessor)
 
 
 
 
 
Year Ended December 31,
 
 
Period from January 1 through December 31,
 
Increase (Decrease)
 
2015
 
 
2014
 
$
 
%
Total non-coal revenue
$
9.6

 
 
$
26.6

 
$
(17.0
)
 
(63.9
)%
Non-coal revenues, primarily from limestone sales, non-coal services and other miscellaneous revenue was $9.6 million for the year ended December 31, 2015, a decrease of $17.0 million, from $26.6 million for the predecessor period ended December 31, 2014. Other miscellaneous revenue decreased by $17.7 million to $2.7 million for the year ended December 31, 2015 from $20.4 million in the prior year, due primarily to the receipt of $19.5 million in litigation settlement proceeds from a former customer compensating us for lost profits on coal sales due to a wrongfully terminated coal supply agreement in the predecessor period ended December 31, 2014. The $17.7 million decrease in miscellaneous revenue and $1.8 million decrease in limestone revenue was offset in part by a $1.9 million increase in non-coal services and a $0.6 million increase in oil and gas royalties the year ended December 31, 2015.
Cost of Coal Revenues
 
Westmoreland
Resource
Partners, LP
 
 
Oxford Resource Partners, LP
 
 
 
 
 
(Successor)
 
 
(Predecessor)
 
 
 
 
 
Year Ended December 31,
 
 
Period from January 1 through December 31,
 
Increase (Decrease)
 
2015
 
 
2014
 
$
 
%
Total Cost of Coal Revenue
$
307.0

 
 
$
258.6

 
$
48.4

 
18.7
%

51


WESTMORELAND RESOURCE PARTNERS, LP AND SUBSIDIARIES

Cost of coal revenues (excluding DD&A) was $307.0 million for the year ended December 31, 2015, an increase of $48.4 million, or 18.7%, from $258.6 million for the predecessor period ended December 31, 2014. The increase was primarily attributable to an increase of 2.9 million in tons sold, which corresponds to a $131.1 million increase in cost of coal revenues, partially offset by a decrease in the cost to produce coal of $9.73 per ton, or an aggregate $82.7 million, for the year ended December 31, 2015.
Depreciation, Depletion and Amortization
 
Westmoreland
Resource
Partners, LP
 
 
Oxford Resource Partners, LP
 
 
 
 
 
(Successor)
 
 
(Predecessor)
 
 
 
 
 
Year Ended December 31,
 
 
Period from January 1 through December 31,
 
Increase (Decrease)
 
2015
 
 
2014
 
$
 
%
Depreciation, depletion and amortization
$
54.5

 
 
$
39.3

 
$
15.2

 
38.7
%
DD&A expense was $54.5 million for the year ended December 31, 2015, an increase of $15.2 million, or 38.7%, from $39.3 million for the year ended December 31, 2014. Depreciation expense increased $12.6 million, or 47.2%, to $39.3 million for the year ended December 31, 2015, from $26.7 million for the year ended December 31, 2014, the increase was primarily attributable to the August 1, 2015 Kemmerer Drop. Amortization expense was $6.9 million for the year ended December 31, 2015, a $0.4 million decrease from $7.3 million for the year ended December 31, 2014. The decrease was primarily attributable to changes in the amortization for asset retirement costs based on revisions to cost estimates and useful lives. Depletion expense was $8.3 million for the year ended December 31, 2015, a $3.0 million increase from $5.3 million for the year ended December 31, 2014, which was primarily attributable to an increase in the depletion rate per ton.
Selling and Administrative
 
Westmoreland
Resource
Partners, LP
 
 
Oxford Resource Partners, LP
 
 
 
 
 
(Successor)
 
 
(Predecessor)
 
 
 
 
 
Year Ended December 31,
 
 
Period from January 1 through December 31,
 
Increase (Decrease)
 
2015
 
 
2014
 
$
 
%
Total selling, general and administrative
$
17.1

 
 
$
20.5

 
$
(3.4
)
 
(16.6
)%
Selling and administrative expenses were $17.1 million for the year ended December 31, 2015, a decrease of $3.4 million, or 16.6%, from $20.5 million for the predecessor period ended December 31, 2014. The decrease is primarily the result of one-time expenses resulting from the WCC transactions which includes $2.0 million in equity-based compensation expense related to change of control provisions for the LTIP for the predecessor period ended December 31, 2014 and other cost reduction efforts made during the year ended December 31, 2015

52


WESTMORELAND RESOURCE PARTNERS, LP AND SUBSIDIARIES

Nonoperating Results (including interest expense, interest income, (loss) gain on debt extinguishment other income, change in fair value of warrants, and net loss attributable to noncontrolling interest)
 
Westmoreland
Resource
Partners, LP
 
 
Oxford Resource Partners, LP
 
 
 
 
 
(Successor)
 
 
(Predecessor)
 
 
 
 
 
Year Ended December 31,
 
 
Period from January 1 through December 31,
 
Increase (Decrease)
 
2015
 
 
2014
 
$
 
%
Interest expense
$
(30.8
)
 
 
$
(27.8
)
 
$
(3.0
)
 
10.8
 %
Interest income
0.9

 
 

 
0.9

 
100.0
 %
(Loss) gain on debt extinguishment

 
 
0.5

 
(0.5
)
 
(100.0
)%
Other income
0.3

 
 

 
0.3