Attached files

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EX-31.1 - EXHIBIT 31.1 - Westmoreland Resource Partners, LPexh311.htm
EX-95.1 - EXHIBIT 95.1 - Westmoreland Resource Partners, LPexh951-minesafety.htm
EX-32.1 - EXHIBIT 32.1 - Westmoreland Resource Partners, LPexh32.htm
EX-31.2 - EXHIBIT 31.2 - Westmoreland Resource Partners, LPexh312.htm
EX-23.1 - EXHIBIT 23.1 AUDITOR CONSENT - Westmoreland Resource Partners, LPexh231-eyconsent.htm
EX-21.1 - EXHIBIT 21.1 LISTING OF SUBSIDARIES - Westmoreland Resource Partners, LPexh211-listingofsubsidaries.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, 2016
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 300, 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 $4.2 million, based on the reported closing price of the common units as reported on the New York Stock Exchange on June 30, 2016. In accordance with Regulation S-K Subpart 229.1, Westmoreland Resource Partners, LP ("the Partnership" or "WMLP") is a Non-Accelerated Filer because the Partnership is a majority-owned subsidiary of Westmoreland Coal Company ("Parent" or "WCC").
As of March 10, 2017, 1,284,840 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
 
 
 
 
 
15
16
 


WESTMORELAND RESOURCE PARTNERS, LP AND SUBSIDIARIES

Cautionary Note Regarding Forward-Looking Statements
This Annual Report and materials we have filed or will file with the Securities and Exchange Commission (as well as information included in our other written or oral statements) contain or will contain certain statements that are forward-looking within the meaning of the Private Securities Litigation Reform Act of 1995. These statements are based on our expectations and assumptions at the time they are made and are not guarantees of future performance. Because forward looking statements relate to the future, they involve certain risks, uncertainties and assumptions that are difficult to predict. Actual outcomes and results may differ materially from those expressed in, or implied by, our forward-looking statements. Words such as "expects," "intends," "anticipates," "believes," "estimates," "guides," "provides guidance," "provides outlook" and other similar expressions or future or conditional verbs such as "may," "will," "should," "would," "could," and "might" are intended to identify such forward-looking statements. Readers of this Annual Report should not rely solely on the forward-looking statements and should consider all uncertainties and risks discussed in the "Risk Factors" section and throughout the Annual Report. The statements are only as of the date they are made, and the Partnership undertakes no obligation to update any forward-looking statement. Possible events or factors that could cause results or performance to differ materially from those expressed in our forward-looking statements include but are not limited to the following:
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 the Environmental Protection Agency’s inquiries and regulations on the operations of the power plants to which we provide coal;
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;
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, including how power prices affect our customers’ decision to run their plants;
Seasonal variations and inclement weather may cause fluctuations in our operating results, profitability, cash flow and working capital needs related to our operating segments;
The availability and costs of key supplies or commodities, such as diesel fuel, steel and explosives;
Potential title defects or loss of leasehold interests in our properties, which could result in unanticipated costs or an inability to mine the properties;
The effect of consummating financing, acquisition and/or disposition transactions;
The inability to renew our mineral leases or material changes in lease royalties;
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;

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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; and
Other factors that are described under the heading “Risk Factors” found in reports filed with the Securities and Exchange Commission including our Annual Reports on Form 10-K and our Quarterly Reports on Form 10-Q.
Unless otherwise specified, the forward-looking statements in this report speak as of the filing date of this report. Factors or events that could cause our actual results to differ may emerge from time-to-time, and it is not possible for us to predict all of them. We undertake no obligation to publicly update any forward-looking statements, whether because of new information, future developments or otherwise, except as may be required by law.

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WESTMORELAND RESOURCE PARTNERS, LP AND SUBSIDIARIES

PART I
Introduction
This report is both our 2016 Annual Report to unitholders and our 2016 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.


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Item 1. Business
Overview
We are a low-cost producer and marketer of high-value thermal coal to large electric utilities with coal-fired power plants under long-term coal sales contracts. We also market to industrial users, and are the largest producer of surface mined coal in Ohio. We focus on acquiring thermal coal reserves that we can efficiently mine with our large-scale equipment and take advantage of close customer proximity through mine-mouth power plants and strategically located rail and barge transportation. Our reserves and operations are well positioned to serve our primary market areas of the Midwest, Northeast and Rocky Mountain regions of the United States ("U.S."). Our operations are located in Ohio and Wyoming. We sold 7.8 million tons of coal in 2016.
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 coal using 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 ("GP") was acquired by WCC, a Delaware corporation, and our executive offices were moved to Englewood, Colorado. WCC directly owns 100% of our GP and, as of the date of this filing, 93.72% of the beneficial limited partner interest on a fully diluted basis. We are managed by WCC through our GP, and all executives, officers and employees who provide services to us (which are approximately 640 employees) are employed by WCC. WCC’s common stock trades on the NASDAQ under the symbol “WLB.” We conduct our operations through our subsidiaries and our principal sources of cash are distributions from our operating subsidiaries. We operate in a single business segment and have seven operating subsidiaries. See Exhibit 21.1 - List of Subsidiaries for an organizational chart. The following map shows our current operations:
wmlpmap.jpg
Series B Convertible Units
On October 28, 2016, we issued 4,512,500 Series B Convertible Units representing limited partner interests in the Partnership (the “Series B Units”) to WCC in exchange for WCC’s 4,512,500 common units (the “Exchange”). Upon issuance of the Series B Units in the Exchange, WCC’s common units were canceled. The Series B Units do not share in distributions with the common units and are convertible at the option of the holder on a one-for-one basis into common units on the day after the record date for a cash distribution on the common units in which the Partnership is unable to make such a distribution without exceeding its restricted payment basket under the 2014 Financing Agreement (as defined in Note 13. Long-Term Debt to the consolidated financial statements). The Series B Units will convert automatically upon a change of control or a dissolution or liquidation of the Partnership. The Series B 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 B Units are entitled to vote as a separate class on any matters that materially adversely affect the rights or preferences of the Series B Units in relation to other classes of partnership interests or as required by law. Concurrently with the Exchange, we entered into Amendment No. 2 to the Partnership Agreement (as defined in Note 1. Organization And Presentation and Note 17. Partners' Capital And Convertible Units to the consolidated financial statements), which established the terms of the Series B Units.

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Properties
During 2016, WMLP operated one surface mine in Wyoming and four active mining complexes in Ohio comprising ten surface mines. The Ohio operations include a river terminal on the Ohio River, two washing facilities, two rail loadout facilities and a tipple facility. The mines are a combination of area, contour, auger and highwall mining methods using truck/shovel and truck/loader equipment along with large production dozers. WMLP owns and operates six augers throughout its mining complexes. WMLP also utilizes highwall miner systems. WMLP owns or leases most of the equipment utilized in its mining operations and employs preventive maintenance and rebuild programs to ensure that its equipment is well maintained. During 2016, WMLP leased or subleased to others approximately 24.3 million tons of the total tons owned or controlled by WMLP. We believe that we have satisfied all lease conditions in order to retain the properties and keep the leases in place.
Our reported proven and probable coal reserves are those we believe can be economically and legally extracted or produced at the time of the filing of this Annual Report on Form 10-K. In determining whether our proven and probable coal reserves meet this economic and legal standard, we take into account, among other things, our potential ability or inability to obtain mining permits, the possible necessity of revising mining plans, changes in future cash flows caused by changes in estimated future costs, changes in mining permits, variations in quantity and quality of coal, and varying levels of demand and their effects on selling prices. The following table provides coal reserve quantities from mines we own or control:
 
December 31, 2016
 
(In thousands of tons)
Coal reserves(1):
 
Proven
118,785

Probable
16,442

Total proven and probable reserves(2)
135,227

Permitted reserves
58,614

Current year production
7,088

(1)
The 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.
(2)
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.
Substantially all of our properties and assets are encumbered by liens securing our and our subsidiaries’ outstanding indebtedness. In addition, borrowings under the Revolver are secured by first priority liens on our and our wholly owned subsidiaries' accounts receivable, inventory and certain other specified assets. See Note 13. Long-Term Debt to the consolidated financial statements.

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WESTMORELAND RESOURCE PARTNERS, LP AND SUBSIDIARIES


The following table provides summary information regarding our principal mining operations as of December 31, 2016 (all tons data presented in thousands):
WMLP Mines
Cadiz
Tuscarawas
Belmont
New Lexington
Noble
(1)
Plainfield (1)
Muhlen-berg (1)
Tusky
(1)
Kemmerer
Previously owned by
The Ohio mines were previously owned by Oxford Resource Partners, LP which was purchased by WCC in December 2014.
Chevron Mining Inc., purchased 2012
Currently owned by
 The Ohio mines are currently owned by Oxford Mining Company, LLC except Muhlenberg which is owned by Oxford Mining Company - Kentucky, LLC.
Westmore- land Kemmerer, LLC
County, State
  Jefferson & Harrison, Ohio
  Stark & Tuscarawas, Ohio
  Belmont, Ohio
  Perry, Athens & Morgan, Ohio
  Noble & Guernsey, Ohio
 Muskingum, Guernsey & Coshocton, Ohio
 Muhlenberg & McLean, Kentucky
  Harrison & Tuscarawas, Ohio
 Lincoln, Wyoming
Proven reserves
4,743

4,567

7,910

3,804

229

3,622

1,227

18,965

73,718

Probable reserves
1,156


312

173



568

5,366

8,867

Total reserves
5,899

4,567

8,222

3,977

229

3,622

1,795

24,331

82,585

Permitted reserves
5,466

1,946

1,327

1,022


282

1,227

16,720

30,624

2016 tons produced
1,819

450

334

381





4,104

Production capacity
2,580

600

660

600

 N/A

 N/A

 N/A

 N/A

7,000

2016 tons sold
2,558

456

333

390





4,106

2015 tons sold
2,125

673

644

551

17




4,471

2014 tons sold
3,152

1,140

403

685

251




4,399

Estimated mine life with current plan
2022
2019
2019
2019
N/A
N/A
N/A
N/A
2026
Lessor (2)
 Private parties, Consol
 Private parties
 Private parties
 AEP, Private parties
 Private parties
 Private parties
 Private parties
 Private parties
Fed Gov, Private parties
Lease term
 Varies
 Varies
 Varies
 Varies
 Varies
 Varies
 Varies
 Varies
Varies
Coal seam
Pittsburgh, Redstone & Meigs Creek
Lower & Middle Kittanning, Upper Freeport, Mahoning, Brookville
Pittsburgh, Meigs Creek & Waynesburg
Lower & Middle Kittanning, Pittsburgh
Pittsburgh
Middle Kittanning
Tradewater & Carbondale Formations
Middle Kittanning & Upper Freeport
Adaville Series
Coal type
 Bituminous
 Bituminous
 Bituminous
 Bituminous
 Bituminous
 Bituminous
 Bituminous
 Bituminous
Sub-bituminous
Approx. heat content in 2016 (BTU/lb.)
11,420
11,768
11,742
11,550
11,286
11,711
11,424
12,900
10,019
Approx. sulfur content in 2016 (%)
2.60
3.80
4.50
3.80
5.30
4.40
3.50
2.10
0.71
Major customers (2)
 AEP & EKPC
 AEP
 AEP & EKPC
 AEP
N/A
N/A
N/A
N/A
PacifiCorp Energy, Inc.
Delivery method
Truck, rail, barge
Truck
Truck, barge
Truck, rail
N/A
N/A
N/A
N/A
Truck, rail, conveyor
Machinery
3 coal crushers with truck scales, rail load-out facility
Coal crusher with truck scale, blending facility, prep plant
Coal crusher, blending facility
Coal crusher with truck scale, rail load-out facility
N/A
N/A
N/A
N/A
Trucks, shovels, dozers
Gross Property, Plant & Equipment (in millions)
The Ohio mines' gross property, plant and equipment as of December 31, 2016 was $203.6 million.
$156.4
Year complex opened
2000
2003
1999
1993
2006
1990
2009
2003
1950
Tons mined since inception
452,647
192,984
16,172
175,059
191,730
107,489
107,489
15,148
192,841
____________________
(1) These mines were inactive during 2016.
(2) American Electric Power Company, Inc. (“AEP”); East Kentucky Power Cooperative (“EKPC”)

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Cadiz. The Cadiz complex consists of the Sandy Ridge, Harrison, Daron, Harrah and Ellis mines. Coal produced from these mines 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, 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 washing facility then transported by truck to the customer after processing is completed. This mine uses the area, contour, auger and highwall miner methods of surface mining.
Tuscarawas. The Tuscarawas complex consists of the East Canton, Garrett, Hunt and Stillwater mines. Coal produced from these mines is transported by truck directly to our customers, trucked to our Barb Tipple blending and coal crushing facility or trucked to our Conesville or Strasburg washing facilities. The coal is then transported by truck to the customer after washing is completed. This mine uses the area, contour, auger and highwall miner methods of surface mining.
Belmont. The Belmont complex consists of the Speidel, Shugert, Buttermilk and Wheeling Valley mines. Coal produced from these mines is primarily transported to our Bellaire river terminal on the Ohio River where it is crushed and blended and then transported by barge to the customer, or it is transported by truck to our Barb Tipple blending and crushing facility which is adjacent to a customer's power plant near Coshocton, Ohio, or it is transported to our Conesville washing facility and then transported by truck to the customer. This mine uses area, contour, auger and highwall miner methods of surface mining.
New Lexington. The New Lexington complex consists of the Avondale and New Lexington mines. Coal produced from these mines is transported by truck or 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 mine is trucked to our Conesville washing facility and then transported by truck to the customer. This mine uses the area and auger methods of surface mining.
Kemmerer. The Kemmerer mine in Wyoming transports the coal it produces via conveyor belt to the adjacent Naughton Power Station or it is shipped via short haul rail or truck to various industrial customers. This mine utilizes truck, shovel and dozer surface mining methods.
Customers
Our primary customers are electric utility companies that purchase coal for terms of one year or longer. We also supply coal on a short-term or spot market basis for some of our customers. We provide coal delivery via conveyor belt to our mine-mouth customers and also sell coal on a Freight On Board ("FOB") basis to our other customers via truck, rail or barge. The purchaser of coal normally bears the cost of transportation and risk of loss from load-out to its final destination. In 2016, WMLP derived approximately 77% of its revenues from coal sales to three customers: AEP (38%), PacifiCorp Energy, Inc. (29%), and East Kentucky Power Cooperative (10%). We sell the majority of our WMLP tons under contracts with a weighted average remaining supply obligation term of approximately two years. A portion of these sales were facilitated by coal brokers.
The Kemmerer mine supplies the adjacent Naughton Power Station via conveyor belt under an agreement that expires in December 2021. The Kemmerer mine also supplies various industrial customers, including Tronox - Green River and Granger and Tata Chemicals North America Inc., through long-term contracts extending to 2026. These industrial customers are supplied via Union Pacific rail and truck. Prices under the supply agreements are based upon certain actual mine costs and certain inflation/commodity indices.
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, 2016, approximately 98.2% 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 of our 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

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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.
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 six years remaining on our lease for the underground coal reserves, and the related sublease. The sublessee has the option at any time after December 31, 2022 to elect to have us assign its interest to the sublessee for defined and predetermined consideration. For the years ended December 31, 2016 and 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 right sales in 2016 or 2015. For each of the years ended December 31, 2016 and 2015, WMLP generated $0.9 million in oil and gas royalty revenue.
Limestone Revenues - At our Daron and Strasburg mining complexes, limestone is removed in order to access the underlying coal. We sell this limestone to a third party who crushes it 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 years ended December 31, 2016 and 2015, we produced and sold 0.4 million and 0.7 million tons of limestone, respectively. Revenues from limestone sales included $1.8 million and $2.9 million for the same time periods, respectively.
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. See Note 6. Restricted Investments And Bond Collateral to the consolidated financial statements for our cash deposits, restricted investments and 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.
Competition
The North American coal industry is intensely competitive. In addition to competition from other coal producers, we compete with producers of alternative fuels used for electrical power generation, such as nuclear energy, natural gas, hydropower, petroleum, solar and wind. Costs and other factors such as safety, environmental and regulatory considerations relating to alternative fuels affect the overall demand for coal as a fuel.
The majority of our mines focuses on niche coal markets where we take advantage of long-term coal contracts with neighboring power plants. These mines gives us a competitive advantage based on two factors:
we are among the most economic suppliers to our principal customers as a result of transportation advantages over our competitors; and

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nearly all of the power plants we supply were specifically designed to use our coal.
The Ohio operations do not compete with producers of metallurgical coal or lignite. However, we do have limited competition from producers of Powder River Basin coal (sub-bituminous coal) in our target market area for bituminous coal. WMLP competes on the basis of delivered price, coal quality and reliability of supply. Its principal direct competitors are other coal producers, including (listed alphabetically) Alliance Resource Partners, L.P., Alpha Natural Resources, CONSOL Energy, Contura Energy, Foresight Energy, Hallador Energy Company, Murray Energy Corporation, Peabody Energy Corp., Rhino Resource Partners, L.P. and various other smaller, independent producers.
Washing Facilities
Depending on coal quality and customer requirements, some raw/crushed 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 washing process that physically separates impurities from the coal. This processing upgrades the quality and heating value of the coal by generally removing ash, but it entails additional expense and results in some loss of coal. The Partnership owns and operates two washing facilities as follows:
Strasburg (Strasburg, Ohio): Throughput capacity of 200 tons of raw coal per hour and operated at a 50.0% utilization rate in 2016;
Conesville (Coshocton County, Ohio): Throughput capacity of 500 tons of raw coal per hour and operated at an 83.0% utilization rate in 2016 from January to April until it was idled the remainder of the year due to poor market conditions. This facility is adjacent to a customer’s power plant.
Seasonality
Our coal business has historically experienced variability in its results due to the effect of seasons. We are impacted by seasonality due to weather patterns and our customers’ 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 some 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
Safety
Following passage of The Mine Improvement and New Emergency Response Act of 2006, amending the Federal Mine Safety and Health Act of 1977, MSHA significantly increased the oversight, inspection and enforcement of safety and health standards and imposed safety and health standards on all aspects of mining operations. There has also been a dramatic increase in the dollar penalties assessed by MSHA for citations issued over the past several years. Most of the states in which we operate have inspection programs for mine safety and health. Collectively, federal, state and provincial 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 Westmoreland Resource Partners, LP. We use a grass roots approach, encouraging and promoting employee involvement in safety and accept input from all employees; we feel employee involvement is a pillar of our safety excellence. Safety performance at our mines was as follows:
 
2016
 
2015
 
Reportable Rate
 
Lost Time Rate
 
Reportable Rate
 
Lost Time Rate
WMLP Mines
0.84

 
0.28

 
1.05

 
0.35

U.S. National Surface Average
1.35

 
0.88

 
1.62

 
1.09

Percentage
62
%
 
32
%
 
65
%
 
32
%

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Regulations
We are subject to extensive regulation with respect to environmental and other matters by federal, state, and local authorities in the U.S. Regulations to which we are subject include, but are not limited to, the following:
U. S. Federal Regulations
Surface Mining Control & Reclamation Act of 1977
Clean Air Act
Clean Water Act
Endangered Species Act
Resource Conservation and Recovery Act
Comprehensive Environmental Response, Compensation and Liability Act
Emergency Planning and Community Right to Know Act
Toxic Substances Control Act
Migratory Bird Treaty Act
Various other climate change laws and initiatives
The U.S. Environmental Protection Agency (the "EPA") and/or other authorized federal or state agencies administer and enforce these U.S. regulations. We are also subject to extensive regulation regarding safety and health matters pursuant to the United States Mine Safety and Health Act of 1977, which is enforced by the U.S. Mine Safety and Health Administration (“MSHA”). Non-compliance with federal, tribal and state laws and regulations could subject us to material administrative, civil or criminal penalties or other liabilities, including suspension or termination of operations. In addition, we may be required to make large and unanticipated capital expenditures to comply with future laws, regulations or orders as well as future interpretations and more rigorous enforcement of existing laws, regulations or orders. Our reclamation obligations under applicable environmental laws will be substantial. Certain of our coal sales agreements contain government imposition provisions that allow the pass-through of compliance costs in some circumstances.
The following provides summaries of certain U.S. federal regulations to which we are subject and their effects on us:
Surface Mining Control and Reclamation Act ("SMCRA"). 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. This difficulty in permitting affects the availability of coal reserves at our coal mines. In January 2016, the Federal Bureau of Land Management announced a moratorium on new coal leases on federal lands. The moratorium does not affect existing leases. It is our policy to comply in all material respects with the requirements of the SMCRA and the state and tribal laws and regulations governing mine reclamation.
In December 2016, the OSM published the final Stream Protection Rule to reduce the environmental impact of surface coal mining operations.  The rule included the expansion of baseline data requirements and post-mining restoration requirements.  Under the Congressional Review Act, Congress approved H.J. Res. 38, disapproving the Stream Protection Rule.  President Trump signed H.J. Res. 38 on February 16, 2017.  The regulations in effect are those that were in place on January 18, 2017.  OSM is in the process of developing a final rule for publication in the Federal Register to amend all the regulations altered by the Stream Protection Rule back to the form in which those regulations existed on January 18, 2017.
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 greenhouse gases ("GHG"). The air emissions programs, regulatory initiatives and standards that may affect our operations, directly or indirectly, include, but are not limited to, the following:

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Greenhouse Gas Emissions Standards. In August of 2015, the EPA finalized standards for greenhouse gases for new and modified electric generating units ("EGUs") referred to as “new source performance standards” ("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 a major obstacle to the construction and development of any new coal-fired generation capacity. States and industry challenged the rule in the D.C. Circuit court, with oral arguments scheduled for April 17, 2017. 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, for example, is faced with greater than 40% emission reductions from a 2012 baseline. Under the rule, the states had until September of 2016 to submit plans to the EPA to implement and enforce the state-specific BSER, although two-year extensions could have been 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 stay delayed the implementation of the rule, including the state plan submittal dates. The D.C. Circuit reviewed the rule under an expedited briefing schedule, and an en banc panel heard oral arguments on September 27, 2016. 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. However, the Trump Administration has indicated that it intends to repeal the Clean Power Plan and it is uncertain whether it will be replaced. In June 2014, the U.S. Supreme Court in UARG v. the 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 2016, the EPA proposed a rule to comply with the U.S. Supreme Court’s ruling by limiting the requirement to obtain permits controlling emissions of greenhouse gases to new large sources of other air pollutants, such as volatile organic compounds or nitrogen oxides, which also emit 100,000 tons per year or more of CO2 (or modifications of these sources that result in an emissions increase of 75,000 tons per year or more of CO2e). Therefore the permit provisions addressing GHG emissions from large industrial sources, such as fossil-fuel fired EGUs, remain in place.
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 in response to requests by industry and 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 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 conducted 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. On April 14, 2016, the EPA issued a final rule confirming its “appropriate and necessary” finding to regulate air toxics, including mercury, from power plants after considering

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costs. The final rule was immediately challenged in the U.S. Court of Appeals for the D.C. Circuit in Murray Energy Corp. v. the EPA and briefing is currently underway.
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 dioxide 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 dioxide 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 finalized additional designations on June 30, 2016, with a supplement on November 29, 2016. For the remaining areas, the areas will be designated by the date determined by the Sulfur Data Requirements Rule. 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. Several industry and business groups, five states, and Murray Energy Corp. challenged the revised standard in the D.C. Circuit. Briefing has been completed and oral argument is scheduled for April 19, 2017. The Trump Administration also has indicated that it may revisit the standard. 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 oxides 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 oxides 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 began 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 began in January 2015, with more stringent phase 2 reductions in January 2017 as necessary. In September 2016, the EPA finalized an update to CSAPR ozone season program that lowered the ozone season emission budgets for the affected states. The update aligned compliance with the July 2018 attainment date for the 2008 ozone NAAQS.
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

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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 sulfur 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 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. 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. Our coal also contains about fifty percent more ash content than our primary competitors, which can translate into a cost disadvantage where post-combustion coal ash must be land filled.
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 (the "Corps") 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, pending court challenges, 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. In January 2017, the Corps issued general nationwide permits for specific activities that are similar in nature and that are determined to have minimal adverse environmental effects. The permits will become effective in March 2017. The Corps reinstated the use of Nationwide Permit 21 for surface coal mining activities. In the event the acreage limits under the permit are exceeded, we will have to obtain individual permits from the Corps which will increase the processing time for future permit applications.
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. The 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

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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 ("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 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; however, the EPA has proposed a rule to comply with the U.S. Supreme Court’s ruling by limiting the requirement to obtain permits controlling emissions of greenhouse gases to large sources of other air pollutants, such as volatile organic compounds or nitrogen oxides, which also emit 100,000 tons per year or more of CO2 (or modifications of these sources that result in an emissions increase of 75,000 tons per year or more of CO2e). Underground coal mines remain subject to the EPA’s GHG Reporting Program, which requires mines to submit annual GHG emission estimates to the EPA, but that program has not been extended to surface coal mines.
The impact of GHG-related legislation and regulations, including a “cap and trade” structure, on us will depend on a number of factors, including whether GHG sources in multiple sectors of the economy are regulated, the overall GHG emissions cap level, the degree to which GHG offsets are allowed, the allocation of emission allowances to specific sources and the indirect impact of carbon regulation on coal prices. We may not recover 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 revenues.

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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. See Note 6. Restricted Investments And Bond Collateral to the consolidated financial statements for the amount of surety bonds posted and cash collateral for reclamation purposes.
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, free of charge, 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 300, Englewood, CO 80112. The information on our website is not part of this Annual Report on Form 10-K.

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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, pursue attractive business opportunities, and allow for 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, see Note 13. Long-Term Debt to the consolidated financial statements.
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, 2016, we had a total outstanding indebtedness of $306.2 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 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.

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Long-term sales and revenues could be significantly affected by environmental regulations and the effects of the environmental lobby.
Environmental regulations that have become increasingly stringent, as well as increased pressure from environmental activists, may reduce demand for our products. For example, a consortium of environmental activists is actively pushing to shut down one-third of the U.S. coal plants by 2020. They are actively lobbying the EPA to require cost-prohibitive pollution control equipment. Rocky Mountain Power, the owner of the Naughton Power Station located adjacent to our Kemmerer mine, which is our Kemmerer mine’s primary customer, has abandoned plans to convert Unit 3 at Naughton to 100% natural gas fueling. Instead, the owner has stated that it intends to retire Naughton Unit 3 at the end of 2017. This retirement will result in the loss of coal sales at our Kemmerer mine. However, Rocky Mountain Power stated that it will continue to consider potential alternatives to allow continued operation beyond 2017. In addition, price protections built into the contract that are in effect from 2017 to 2021 will partially offset the effects of lowered volume following the retirement of Unit 3. Despite these price protections, the lost sales at the Kemmerer mine could have a material adverse effect on the mine’s revenues and profitability and on our operating results. Additional power plants that buy our coal may be considering, or may consider in the future, fuel source conversion, decreased operations or retirement, in order to avoid costly upgrades of pollution control equipment, and such steps, if taken, could result in a reduced demand for our products and materially and adversely affect our revenues and profitability.
In May 2015, the EPA and the Corps 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. In January 2017, the Corps issued general nationwide permits for specific activities, including surface coal mining activities. Permitting challenges may increase if our activities do not qualify for nationwide permit coverage. A change in CWA jurisdiction and permitting requirements could increase or decrease our permitting and compliance costs.
The EPA has executed a final rule relating to the disposal of CCR from electric utilities. The changes to the management of CCR could increase our and our customers’ operating costs and reduce sales of coal.
In December 2016, the OSM published the final Stream Protection Rule to reduce the environmental impact of surface coal mining operations.  The rule included the expansion of baseline data requirements and post-mining restoration requirements.  Under the Congressional Review Act, Congress approved H.J. Res. 38, disapproving the Stream Protection Rule.  President Trump signed H.J. Res. 38 on February 16, 2017.  The regulations in effect are those that were in place on January 18, 2017.  OSM is in the process of developing a final rule for publication in the Federal Register to amend all the regulations altered by the Stream Protection Rule back to the form in which those regulations existed on January 18, 2017. If this rule is not amended, our permitting and compliance costs could increase.
In January 2016, the Federal Bureau of Land Management announced a moratorium on new coal leases on federal lands. The moratorium does not affect our existing federal leases. If the moratorium remains in force, it is unlikely to have a material impact on our ability to conduct future operations because we do not ordinarily bid on federal coal leases.
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, see Item 1 - Business - Long-term Coal Supply Contracts.

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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, 2016, we had sales commitments for approximately 93.4% of our estimated coal production (including purchased coal to supplement our production) for the year ending December 31, 2017. 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, 2016, we derived 97.8% 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 77.3% 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. Examples of conditions that might cause our customers to reduce their purchases include unscheduled maintenance outages at our customers’ power plants, unseasonably moderate weather, 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. 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. See Item 1 - Business - Customers and Item 1 - Business - 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 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;

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competition for production of electricity from non-coal sources, including the price and availability of alternative fuels;
domestic air emission standards for coal-fueled power plants and the ability of coal-fueled power plants to meet these standards by installing scrubbers or other means;
adverse weather, 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 competitive. Increased competition by coal producers or producers of alternate fuels could decrease the demand for, pricing of, or both, for our coal, adversely affecting our business, financial condition and/or results of operations. See 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, 2016. During this period, 78.6% 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 2016, the EIA estimates that coal consumption in the electric power sector totaled 612 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.

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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 current 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, 2016, our liquidity of $30.1 million consisted of $15.1 million of cash and cash equivalents and $15.0 million of availability under our Revolver. Our results of 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

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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 Kemmerer mine 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 other 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 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 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

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recoverable may be material. Should the mineralization and/or configuration of a deposit ultimately turn out to be significantly different from that currently envisaged, then the proposed mining plan may have to be altered in a way that could affect the tonnage and grade of the reserves mined and rates of production and, consequently, could adversely affect the profitability of the mining operations. In addition, short term operating factors relating to the reserves, such as the need for orderly development of ore bodies or the processing of new or different ores, may cause reserve estimates to be modified or operations to be unprofitable in any particular fiscal period. There can be no assurance that our projects or operations will be, or will continue to be, economically viable, that the indicated amount of minerals will be recovered or that they will be recovered at the prices assumed for purposes of estimating reserves.
Any inaccuracies in our estimates of our coal reserves could result in decreased profitability from lower than expected revenues or higher than expected costs.
Our future performance depends on, among other things, the accuracy of our estimates of our proven and probable coal reserves. Our reserve estimates are prepared by our engineers and geologists or by third-party engineering firms and are updated periodically. There are numerous factors and assumptions inherent in estimating the quantities and qualities of, and costs to mine, coal reserves, including many factors beyond our control which include the following:
quality of the coal;
geological and mining conditions, which may not be fully identified by available exploration data and/or may differ from our experiences in areas where we currently mine;
the percentage of coal ultimately recoverable;
the assumed effects of regulation, including the issuance of required permits, taxes, including severance and excise taxes and royalties, and other payments to governmental agencies;
economic assumptions, including assumptions as to future commodity prices;
assumptions concerning the timing for the development of the reserves; and
assumptions concerning equipment and productivity, future coal prices, operating costs, including for critical supplies such as fuel, tires and explosives, capital expenditures and development and reclamation costs.
As a result, estimates of the quantities and qualities of economically recoverable coal attributable to any particular group of properties, classifications of reserves based on risk of recovery, estimated cost of production, and estimates of future net cash flows expected from these properties may vary materially due to changes in the above factors and assumptions. Any inaccuracy in our estimates related to our reserves could result in decreased profitability from lower than expected revenues or higher than expected costs.
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

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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 jurisdictions in which we operate, leading to increasing interest 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 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 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 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 well as potential review by the Supreme Court. The D.C. Circuit issued an expedited briefing schedule for challenges to the rule, and an en banc court heard oral argument on September 27, 2016. However, the Trump Administration has indicated that it plans to repeal the rule and it is uncertain whether it will be replaced. 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 rules would have on our revenues and profitability. See Item 1 - Business - Material Effects of Regulation.
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.
An inability to obtain and/or renew permits necessary for WMLP’s operations could prevent it from mining certain of its 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 and the issuance of the Stream Protection Rule by the OSM in December 2016. 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.

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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/or 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.
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.

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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 U.S. Generally Accepted Accounting Principles ("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 $52.2 million (on a present value basis) at December 31, 2016. 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. See Item 7 - Management’s Discussion and Analysis of Financial Condition and Results of Operations - Critical Accounting Policies and Estimates - Asset Retirement Obligations, Final Reclamation Costs and Reserve Estimates.
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 2016, 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

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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 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 (as defined in Note 1. Organization And Presentation to the consolidated financial statements) 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

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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.
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.

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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, see Item 1 - Business - Material Effects of Regulation.
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. More recently, the new United States Administration and members of the U.S. Congress have stated that they will seek to modify, repeal, or otherwise invalidate all, or certain provisions of, the PPACA. On January 20, 2017, President Trump signed an executive order stating that it is the policy of his Administration to seek the prompt repeal of the PPACA and directed executive departments and federal agencies to waive, defer, grant exemptions from, or delay the implementation of the provisions of the PPACA to the maximum extent permitted by law. Additionally, the U.S. House and Senate recently passed a budget resolution that authorizes congressional committees to draft legislation to repeal all or portions of the PPACA and permits such legislation to pass with a majority vote in the Senate. We will continue to evaluate the impact and status of the PPACA in future periods.
Mining operations are subject to extensive and costly environmental laws and regulations, and such current and future laws and regulations could materially increase our operating costs or limit our ability to produce and sell coal.
The coal mining industry is subject to numerous and extensive federal, state and local environmental laws and regulations, including laws and regulations pertaining to permitting and licensing requirements, air quality standards, plant and wildlife protection, reclamation and restoration of mining properties, the discharge of materials into the environment, the storage, treatment and disposal of wastes, protection of wetlands, surface subsidence from underground mining, and the effects that mining has on groundwater quality and availability. The costs, liabilities and requirements associated with these laws and regulations are significant, time-consuming and may delay commencement or continuation of our operations.
The possibility exists that new laws or regulations (or new judicial interpretations or enforcement of existing laws and regulations) could materially affect our mining operations and our business, financial condition and/or results of operations, either through direct impacts such as those regulating our existing mining operations, or indirect impacts such as those that discourage or limit our customers' use of coal. For example, the EPA and the U.S. Army Corps of Engineers have 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.

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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. 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 April 2014, the U.S. Supreme Court upheld the EPA’s Cross-State Air Pollution Rule, which would require stringent reductions in emissions of nitrogen oxides and sulfur dioxide from power plants in much of the U.S. For more details, see Item 1 - Business - Material Effects of Regulation. 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, and it is unclear how the Trump Administration will approach both previous rules and new rulemakings. 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 already in place, and these limitations will likely require significant emissions control expenditures for many coal-fired power plants. Should the owners of power plants we serve be forced by the EPA to install such technology, the capital requirements could make the continued operation 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

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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.
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 93.91% beneficial limited partner interest in us on a fully diluted basis at December 31, 2016, 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 maintains consolidated 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

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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 the above risk titled "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."
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 0.16% of our common units and the owner of our general partner, WCC, owns 93.91% beneficial limited partner interest on a fully diluted basis at December 31, 2016.
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% 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”).

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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:
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.

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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 2017 for certain administrative services plus reimbursement at cost for other expenses and expenditures. The term of the Agreement expires on December 31 of each calendar year end, and automatically renews for successive one-year periods unless terminated. The reimbursement to our general partner for such 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

33

WESTMORELAND RESOURCE PARTNERS, LP AND SUBSIDIARIES

substantially reduced. Therefore, if we were treated as a corporation for federal tax purposes there could be a material reduction in the anticipated cash flow and after-tax return to a unitholder, likely causing a substantial reduction in the value of our common units.
We are subject to extensive tax laws and regulations, with respect to federal, state and foreign income taxes and transactional taxes such as excise, sales/use, payroll, franchise and ad valorem taxes. New tax laws and regulations and changes in existing tax laws and regulations are continuously being enacted that could result in increased tax expenditures in the future. Further, changes in current state law may subject us to additional entity-level taxation by individual states. Because of widespread state budget deficits and other reasons, several states are evaluating ways to subject partnerships to entity-level taxation through the imposition of state income, franchise and other forms of taxation. Imposition of any such taxes could adversely affect our cash available for distribution to unitholders.
Our partnership agreement provides that, if a law is enacted or existing law is modified or interpreted in a manner that subjects us to taxation as a corporation or otherwise subjects us to entity-level taxation for federal, state or local income tax purposes, the minimum quarterly distribution amount and the target distribution amounts will be adjusted to reflect the impact of that law on us.
The tax treatment of publicly traded partnerships or an investment in our common units could be subject to potential legislative, judicial or administrative changes and differing interpretations, possibly on a retroactive basis.
The present federal income tax treatment of publicly traded partnerships, including us, or an investment in our common units may be modified by administrative, legislative or judicial interpretation at any time. Any modification to the federal income tax laws and interpretations thereof may or may not be applied retroactively. Moreover, any such modification could make it more difficult or impossible for us to meet the exception that allows publicly traded partnerships that generate qualifying income to be treated as partnerships (rather than corporations) for federal income tax purposes, affect or cause us to change our business activities, or affect the tax consequences of an investment in our common units. For example, from time to time, members of the U.S. Congress have considered substantive changes to the existing federal income tax laws that would affect the tax treatment of certain publicly traded partnerships. Further, on January 24, 2017, the U.S. Treasury Department (“Treasury”) and the IRS published in the Federal Register final regulations effective as of January 19, 2017 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 final regulations. 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 could be eliminated in future legislation.
The passage of any legislation effecting changes in federal income tax laws could eliminate or defer certain tax deductions and other preferences that are currently available with respect to coal exploration and development, and any such change could increase the taxable income allocable to our unitholders or the amount of tax payable on that income 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 current 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.
Recently enacted legislation, and proposed but withdrawn Treasury regulations, applicable to us for taxable years beginning after December 31, 2017 alters the procedures for auditing large partnerships and also alters the procedures for assessing and collecting taxes due (including applicable penalties and interest) as a result of an audit. Unless we are eligible to

34

WESTMORELAND RESOURCE PARTNERS, LP AND SUBSIDIARIES

(and choose to) elect to issue revised Schedules K-1 to our partners with respect to an audited and adjusted return, the IRS (and some states) may assess and collect taxes (including any applicable penalties and interest) directly from us in the year in which the audit is completed under the new rules. There can be no assurance that such election will be practical, permissible or effective in all circumstances. If we are required to pay taxes, penalties and interest as the result of audit adjustments, cash available for distribution to our unitholders may be substantially reduced. In addition, because payment would be due for the taxable year in which the audit is completed, unitholders during that taxable year would bear the expense of the adjustment even if they were not unitholders during the audited taxable year.
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.

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WESTMORELAND RESOURCE PARTNERS, LP AND SUBSIDIARIES

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.
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 and the IRS 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. However, the regulations do not specifically authorize all aspects of the proration method we have currently adopted. If the IRS were to successfully 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-1's 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.

36

WESTMORELAND RESOURCE PARTNERS, LP AND SUBSIDIARIES

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. 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.

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WESTMORELAND RESOURCE PARTNERS, LP AND SUBSIDIARIES

Item 1B. Unresolved Staff Comments
None.
Item 2. Properties
See Item 1 - Business - Properties 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. See Note 21. Commitments And Contingencies to the consolidated financial statements for a description of our pending legal proceedings, which information is incorporated herein by reference.
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 Annual Report on Form 10-K.

38

WESTMORELAND RESOURCE PARTNERS, LP AND SUBSIDIARIES

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 10, 2017, the closing market price for our common units was $4.70 per unit. As of this date, we had outstanding 1,284,840 limited partner common units with 10 registered holders of record not including unitholders whose units are held in trust by other entities which makes the actual number of unitholders greater than the number of registered holders of record. We also had 16,215,029 Series A Units, 4,512,500 Series B Units and 35,291 general partner units. In addition, we had outstanding warrants to purchase an aggregate of 166,557 common units. All of the Series A Units, Series B 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
 
Distribution Per Unit
 
Date Paid
First Quarter 2015
 
$
14.36

 
$
8.42

 
$
0.2000

 
May 15, 2015
Second Quarter 2015
 
$
12.23

 
$
8.75

 
$
0.2000

 
August 14, 2015
Third Quarter 2015
 
$
8.94

 
$
6.06

 
$
0.2000

 
November 13, 2015
Fourth Quarter 2015
 
$
7.60

 
$
2.63

 
$
0.2000

 
February 12, 2016
 
 
 
 
 
 
 
 
 
First Quarter 2016
 
$
5.14

 
$
2.38

 
$
0.2000

 
May 13, 2016
Second Quarter 2016
 
$
6.45

 
$
4.47

 
$
0.2000

 
August 12, 2016
Third Quarter 2016
 
$
6.46

 
$
4.82

 
$
0.1333

 
November 14, 2016
Fourth Quarter 2016
 
$
6.90

 
$
5.01

 
$
0.1333

 
February 14, 2017
Cash Distributions
We distribute 100% of our available cash within 45 days after the end of each quarter to unitholders of record and to our GP, subject to the conditions and limitations within the 2014 Financing Agreement. Available cash is determined at the end of each quarter and is generally defined in the Partnership Agreement as all cash and cash equivalents on hand at the end of each quarter less reserves established by our GP in its reasonable discretion for future cash requirements. These reserves are retained to provide for the conduct of our business, the payment of debt principal and interest and to provide funds for future distributions for any one or more of the next four quarters, and to comply with applicable law. Our available cash may also include, if our GP 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.
As quarterly distributions of available cash exceed the target distribution levels established in our partnership agreement, our managing general partner receives distributions based on specified increasing percentages of the available cash that exceeds the target distribution levels. The target distribution levels are based on the amounts of available cash from our operating surplus distributed for a given quarter that exceed the minimum quarterly distribution (“MQD”). Our partnership agreement defines the MQD as $0.1333 per unit ($0.5332 per unit on an annual basis).
Under the quarterly IDR provisions of our partnership agreement, our managing general partner is 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. For the years ended December 31, 2016, 2015 and 2014, we did not allocate to our managing general partner any incentive distributions.
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 - Credit Facilities.

39

WESTMORELAND RESOURCE PARTNERS, LP AND SUBSIDIARIES

Unregistered Sales of Equity Securities
Series A Convertible Units
In August 2015, 15,251,989 Series A Convertible Units were issued to WCC in consideration for its contribution to us of WKL. The Series A Units 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 Units (the “Series A Convertible Unit Distribution”) may, at our Board of Directors' election, be paid in Series A paid-in-kind Units (“Series A PIK Units”). On January 22, 2016 the Board of Director declared a distribution of 404,562 Series A PIK Units in lieu of a $0.20 cash distribution in respect of Series A Convertible Units. On October 28, 2016 the Board of Director declared a distribution of 276,792 Series A PIK Units in lieu of a $0.1333 cash distribution in respect of Series A Convertible Units.
These transactions were exempt from registration pursuant to Section 4(a)(2) of the Securities Act of 1933, as amended (the 'Securities Act").
Series B Convertible Units
On October 28, 2016, we issued 4,512,500 Series B Convertible Units representing limited partner interests in the Partnership (the “Series B Units”) to WCC in exchange for WCC’s 4,512,500 common units (the “Exchange”). Upon issuance of the Series B Units in the Exchange, WCC’s common units were canceled. These transactions were exempt from registration pursuant to the Securities Act.
Issuer Purchases of Equity Securities
During 2016, 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
See Item 12 - Security Ownership of Certain Beneficial Owners and Management and Related Unitholder Matters which is incorporated by reference into this Item 5.
Stock Performance Graph
The following performance graph compares the cumulative total stockholder return on our common units for the five-year period December 31, 2011 through December 31, 2016 with (i) the cumulative total return over the same period of the NYSE MKT Composite Index, (ii) the cumulative total return over the same period of the SPDR S&P Metals and Mining Index, and (iii) our current peer group index, which consists of Alliance Resource Partners LP, Cloud Peak Energy, Hallador Energy Co., and Rhino Resource Partners LP. We do not have a former peer group due to that fact that we previously filed under the Smaller Reporting Company status which did not require a stock performance graph section as part of this Annual Report on Form 10-K. However, due to our current filing status of Non-Accelerated Filer, we have included this graph. The graph assumes that:
You invested $100 in Westmoreland Resource Partners, LP common units and in each index at the closing price on December 31, 2011;
All dividends were reinvested;
Annual re-weighting of the peer group indices; and
You continued to hold your investment through December 31, 2016.
You are cautioned against drawing any conclusions from the data contained in this graph, as past results are not necessarily indicative of future performance. The indices used are included for comparative purposes only and do not indicate an opinion of management that such indices are necessarily an appropriate measure of the relative performance of our common units.

40

WESTMORELAND RESOURCE PARTNERS, LP AND SUBSIDIARIES

wmlpstockperformancegraph.jpg
 
At December 31,
Company/Market/Peer Group
2011
 
2012
 
2013
 
2014
 
2015
 
2016
Westmoreland Resource Partners LP
$
100.00

 
$
34.02

 
$
9.47

 
$
7.70

 
$
3.46

 
$
5.62

NYSE MKT Composite Index
100.00

 
114.50

 
146.34

 
158.40

 
152.03

 
169.26

SPDR S&P Metals and Mining Index
100.00

 
93.40

 
88.37

 
66.04

 
32.67

 
67.31

2016 Peer Group Index2
100.00

 
88.18

 
93.59

 
81.77

 
28.38

 
57.61

2015 Peer Group Index3
100.00

 
N/A
 
N/A
 
N/A
 
N/A
 
N/A
2 2016 Peer Group: Alliance Resource Partners LP, Cloud Peak Energy, Hallador Energy Co., and Rhino Resource Partners LP
3 2015 Peer Group: Not applicable due to filing under the Smaller Reporting Company status for 2015 Form 10-K.


41

WESTMORELAND RESOURCE PARTNERS, LP AND SUBSIDIARIES

Item 6. Selected Financial and Operating Data
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 table presents our selected financial and operating data as of the dates and for the periods indicated and should be read in conjunction with Item 7 - Management’s Discussion and Analysis of Financial Condition and Results of Operations.
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,
 
2016
 
2015
 
2014
 
 
2014
 
2013
 
2012
 
(In thousands)
 
 
(In thousands)
STATEMENT OF OPERATIONS DATA:
 
 
 

 
 

 
 
 

 
 

 
 

Revenues
$
349,340

 
$
384,700

 
$

 
 
$
322,263

 
$
346,767

 
$
373,527

Operating income (loss)
8,873

 
(5,212
)
 
(2,783
)
 
 
2,306

 
(5,930
)
 
(14,563
)
Net loss
(31,585
)
 
(33,688
)
 
(4,406
)
 
 
(24,155
)
 
(23,700
)
 
(26,053
)
Per limited partner common unit (basic and diluted):
 
 
 
 
 
 
 
 
 
 
 
 
Net loss applicable to limited partner common unit
(1.51
)
 
(4.62
)
 
(0.72
)
 
 
(10.92
)
 
(12.84
)
 
(15.24
)
CONSOLIDATED BALANCE SHEET INFORMATION (end of period):
 
 
 
 
 
 
 
 
 
 
 
 
Working capital (deficit)
$
19,827

 
$
4,188

 
$
5,936

 
 
N/A

 
$
(1,452
)
 
$
(84,129
)
Net property, plant and equipment
235,618

 
277,641

 
309,757

 
 
N/A

 
144,426

 
158,483

Total Assets
386,907

 
417,278

 
476,852

 
 
N/A

 
216,711

 
218,838

Total Debt
317,646

 
301,377

 
179,673

 
 
N/A

 
155,632

 
72,389

Unitholders' capital (deficit)
(28,110
)
 
13,154

 
107,987

 
 
N/A

 
(15,967
)
 
73,021

OTHER CONSOLIDATED DATA:
 
 
 
 
 
 
 
 
 
 
 
 
Net cash provided by (used in):
 
 
 
 
 
 
 
 
 
 
 
 
Operating activities
$
41,082

 
$
31,994

 
$
(1,820
)
 
 
$
24,385

 
$
9,716

 
$
31,776

Investing activities
(14,690
)
 
(134,878
)
 
83

 
 
(8,253
)
 
(22,463
)
 
(8,059
)
Financing activities
(15,008
)
 
100,590

 
7,741

 
 
(19,221
)
 
11,859

 
(22,772
)
Capital expenditures
11,566

 
15,680

 

 
 
15,903

 
22,332

 
22,687

Adjusted EBITDA2
79,304

 
66,135

 

 
 
36,296

 
39,058

 
47,917

Distributable cash flow3
$
27,932

 
$
16,402

 
$
(2,922
)
 
 
$
11,510

 
$
(4,119
)
 
$
4,913

Tons sold
7,843

 
8,481

 

 
 
5,631

 
6,602

 
7,350

Distributions paid per unit:
 
 
 
 
 
 
 
 
 
 
 
 
Limited partners:
 
 
 
 
 
 
 
 
 
 
 
 
Common
$
0.7333

 
$
0.6000

 
$

 
 
$

 
$

 
$
1.5125

Series A Convertible
0.4000

 
0.2000

 

 
 

 

 

Series B Convertible

 

 

 
 

 

 

General partner
0.7333

 
0.6000

 

 
 

 

 
1.0750

1See Note 3. Acquisition And Pushdown Accounting to the consolidated financial statements.
2Adjusted EBITDA , a non-GAAP measure, is defined and reconciled to net loss below.
3Distributable Cash Flow, a non-GAAP measure, is defined and reconciled to net loss below.


42

WESTMORELAND RESOURCE PARTNERS, LP AND SUBSIDIARIES

Non-GAAP Financial Measures
Adjusted EBITDA
EBITDA is defined as earnings before interest expense, interest income, income taxes, depreciation, depletion, amortization and accretion expense. Adjusted EBITDA is defined as EBITDA before certain charges to income such as restructuring, impairment, debt extinguishment, foreign exchange and derivative losses and/or gains which are not considered part of earnings from operations for comparison purposes to other companies’ normalized income. 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 as a basis for strategic planning and forecasting 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;
are used by rating agencies, lenders and other parties to evaluate our creditworthiness; 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 income tax expenses or the cash requirements necessary to pay income taxes;
do not reflect changes in, or cash requirements for, our working capital needs; and
do not reflect the significant interest expense, or the cash requirements necessary to service interest or principal payments, on certain of our debt obligations.
In addition, although depreciation and amortization are non-cash charges, the assets being depreciated and amortized will often have to be replaced in the future, and EBITDA and Adjusted EBITDA do not reflect any cash requirements for such replacements. Other companies in our industry and in other industries may calculate EBITDA and Adjusted EBITDA differently from the way that we do, limiting their usefulness as comparative measures. Because of these limitations, EBITDA and Adjusted EBITDA should not be considered as measures of discretionary cash available to us to invest in the growth of our business. We compensate for these limitations by relying primarily on our GAAP results and using EBITDA and Adjusted EBITDA only as supplemental data. The tables below show how we calculated Adjusted EBITDA, including a breakdown by segment, and reconcile Adjusted EBITDA to net income (loss), the most directly comparable GAAP financial measure.
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

43

WESTMORELAND RESOURCE PARTNERS, LP AND SUBSIDIARIES

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. The tables below shows how we calculated EBITDA, Adjusted EBITDA and Distributable Cash Flow and reconciles each of the three to net loss, the most directly comparable GAAP financial measure.
Reconciliation of EBITDA, Adjusted EBITDA and Distributable Cash Flow to Net Loss
 
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,
 
2016
 
2015
 
2014
 
 
2014
 
2013
 
2012
 
(In thousands)
 
 
(In thousands)
Reconciliation of EBITDA, Adjusted EBITDA and Distributable Cash Flow to Net Loss
 
 
 
 
 
 
 
 
 
 
 
 
Net loss
$
(31,585
)
 
$
(33,688
)
 
$
(4,406
)
 
 
$
(24,155
)
 
$
(23,700
)
 
$
(26,053
)
Loss (gain) on extinguishment of debt

 

 
1,623

 
 
(500
)
 
808

 

Income tax expense

 
157

 

 
 

 

 

Interest expense, net of interest income
40,223

 
29,904

 

 
 
27,783

 
20,242

 
11,490

Depreciation, depletion and amortization
50,216

 
54,503

 

 
 
39,315

 
48,081

 
51,170

Accretion of asset retirement obligation
5,618

 
5,085

 

 
 
2,337

 
2,293

 
1,567

EBITDA
64,472

 
55,961

 
(2,783
)
 
 
44,780

 
47,724

 
38,174

Restructuring and impairment charges
11,310

 
656

 
2,783

 
 
75

 
1,761

 
15,650

Legal settlements

 

 

 
 
(17,548
)
 
(2,100
)
 

Recapitalization costs

 

 

 
 
5,470

 

 

Loss/(gain) on sale of assets
3,035

 
6,890

 

 
 
14

 
(372
)
 
(1,692
)
Unit-based compensation
252

 
438

 

 
 
4,559

 
1,441

 
1,262

Other non-cash and non-recurring costs
235

 
2,190

 

 
 
(1,054
)
 
(9,396
)
 
(5,477
)
Adjusted EBITDA
79,304

 
66,135

 

 
 
36,296

 
39,058

 
47,917

Deferred revenue
3,547

 
2,513

 

 
 

 

 

Reclamation and mine closure costs
(14,160
)
 
(8,216
)
 

 
 
(4,999
)
 
(8,666
)
 
(8,966
)
Maintenance capital expenditures & other
(12,413
)
 
(15,763
)
 

 
 
(14,066
)
 
(18,640
)
 
(23,613
)
Pension and postretirement medical

 
2,552

 

 
 

 

 

Cash interest expense, net of interest income
(28,346
)
 
(20,740
)
 
(2,922
)
 
 
(15,952
)
 
(12,258
)
 
(9,461
)
Legal and insurance settlement proceeds

 

 

 
 
17,548

 
2,100

 
600

Other

 
(10,079
)
 

 
 
(7,317
)
 
(5,713
)
 
(1,564
)
Distributable Cash Flow
$
27,932

 
$
16,402

 
$
(2,922
)
 
 
$
11,510

 
$
(4,119
)
 
$
4,913

1See Note 3. Acquisition And Pushdown Accounting to the consolidated financial statements.


44

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 Item 1A - Risk Factors.
Overview
See Item 1 - Business - Overview.
We sell almost all of our coal under multi-year agreements to electric generation companies. These multi-year (along with some spot-less than one year in length) coal contracts oftentimes 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 such as the PPI-light fuel oils index, 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. We manage these items through strategic sourcing contracts in normal quantities with our suppliers and may use derivatives from time-to-time.
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, international and domestic economic conditions, power plant outages and other factors discussed herein.
Results of Operations 
Items that Affect Comparability of Our Results
For 2016 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 millions):
 
Westmoreland Resource Partners, LP
 
 
Oxford Resource Partners, LP
 
(Successor)
 
 
(Predecessor)
 
For the Year Ended December 31,
 
Period of December 31,
 
 
Period from January 1 through December 31,
 
2016
 
2015
 
2014
 
 
2014
Items that Affect Comparability of Our Results
 
 
 
 
 
 
 
 
Acquisition and transaction costs
$

 
$
2.6

 
$

 
 
$

Restructuring and impairment charges
11.3

 
0.7

 
2.8

 
 
0.1

Loss (gain) on extinguishment of debt

 

 
1.6

 
 
(0.5
)
Recapitalization costs

 

 

 
 
5.5

Legal and insurance settlement proceeds

 

 

 
 
(17.5
)
Debt issuance costs

 

 

 
 
(7.0
)
Total Impact
$
11.3

 
$
3.3

 
$
4.4

 
 
$
(19.4
)
Items recorded in 2016:
We incurred $11.3 million in impairment charges comprised of $8.1 million at the Ohio mines from excess equipment due to mine plan changes and $3.2 million at the Kemmerer mine related to a shovel that was scrapped for parts.
Items recorded in 2015:
We incurred $2.6 million in various investment banker and legal costs related to the Kemmerer Drop.

45

WESTMORELAND RESOURCE PARTNERS, LP AND SUBSIDIARIES

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 WCC 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 WCC 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 Ohio mines.
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 WCC'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.
Year Ended December 31, 2016 Compared to December 31, 2015
 
Year Ended December 31,
 
Increase / (Decrease)
 
2016
 
2015
 
$
 
%
 
(In millions)
Total revenues
$
349.3

 
$
384.7

 
$
(35.4
)
 
(9.2
)%
Net loss
(31.6
)
 
(33.7
)
 
(2.1
)
 
(6.2
)%
Adjusted EBITDA(1)
79.3

 
66.1

 
13.2

 
20.0
 %
(1)Adjusted EBITDA , a non-GAAP measure, is defined and reconciled to net loss in Item 6 - Selected Financial and Operating Data.
Revenue decreased primarily as a result of continued pricing softness in Ohio. Whether this decrease persists in future years is dependent upon fluctuations in market demand in the region. Net loss decreased and Adjusted EBITDA increased primarily due to lower fuel and labor costs at our Ohio mines and the impact of cost savings initiatives at our Kemmerer mine which are expected to continue into the future.
Coal and Non-Coal Revenues
 
Year Ended December 31,
 
Increase / (Decrease)
 
2016
 
2015
 
$
 
%
 
(In millions)
Total coal revenues
$
345.5

 
$
375.1

 
$
(29.6
)
 
(7.9
)%
Total non-coal revenues
3.8

 
9.6

 
(5.8
)
 
(60.4
)%
Coal sales revenue decreased due to a 7.5% decrease in tons sold which amounted to $28.3 million. This decrease was compounded by a decrease in the average sales price per ton of $0.17 or an aggregate $1.3 million. Non-coal revenues, primarily from limestone sales, non-coal services and other (miscellaneous) revenue decreased due to a $2.6 million decrease in non-coal services due to $2.4 million in non-recurring coal handling and transportation service revenue performed on behalf of a subsidiary of WCC during 2015. Additionally, limestone revenue decreased $1.1 million and other (miscellaneous) revenue decreased $2.1 million due to generating $1.8 million in June 2015 compared to $0.6 million in June 2016 in lost coal fees for granting two respective pipeline right-of-ways to multiple third parties.

46

WESTMORELAND RESOURCE PARTNERS, LP AND SUBSIDIARIES

Cost and Expenses
 
Year Ended December 31,
 
Increase / (Decrease)
 
2016
 
2015
 
$
 
%
 
(In millions)
Cost of coal revenues
$
262.8

 
$
307.0

 
$
(44.2
)
 
(14.4
)%
Depreciation, depletion and amortization
50.2

 
54.5

 
(4.3
)
 
(7.9
)%
Selling and administrative
12.6

 
17.1

 
(4.5
)
 
(26.3
)%
Cost of coal revenues decreased primarily due to 0.6 million less tons sold in 2016 than in 2015 which corresponds to a $23.2 million decrease in cost of coal revenues, compounded by a decrease in the cost to produce coal of $2.69 per ton, or an aggregate $21.0 million, for the year ended December 31, 2016. Depreciation, depletion and amortization expense decreased primarily due to a smaller operating fleet as part of our effort to reduce costs. Selling and administrative expenses decreased due to reduced headcount, less reliance on outside services and other cost saving efforts during the twelve months ended December 31, 2016.
Nonoperating Results
 
Year Ended December 31,
 
Increase / (Decrease)
 
2016
 
2015
 
$
 
%
 
(In millions)
Interest expense
$
(41.1
)
 
$
(30.8
)
 
$
(10.3
)
 
(33.4
)%
Interest income
0.9

 
0.9

 

 
 %
Other income

 
0.3

 
(0.3
)
 
(100.0
)%
Change in fair value of warrants
(0.3
)
 
1.3

 
(1.6
)
 
*

* Not meaningful
Interest expense increased due to the $120.0 million in additional debt incurred in connection with the Kemmerer Drop on August 1, 2015. Interest income was stable year over year due to a relatively stable balance of cash on hand upon which interest income is earned. In 2016, we recognized expense from the change in fair value of warrants of $0.3 million which is the increase in value of our units traded on the NYSE during 2016 compared to 2015.
Year Ended December 31, 2015 (Successor) Compared to Period of January 1, 2014 through December 31, 2014 (Predecessor) 
 
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
 
$
 
%
 
(In millions)
 
 
(In millions)
 
 
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 , a non-GAAP measure, is defined and reconciled to net income (loss) in Item 6 - Selected Financial and Operating Data.
Revenue increased due to the Kemmerer Drop offset by a decrease in the average sale price per ton as is discussed in the Coal and Non-coal Revenues section immediately below. Net loss increased due to the factors of increasing revenue which were more than offset by increases in expenses as is discussed in the Cost of Coal Revenues section below. Adjusted EBITDA increased primarily due to the Kemmerer Drop which added $38.3 million.

47

WESTMORELAND RESOURCE PARTNERS, LP AND SUBSIDIARIES

Coal and 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
 
$
 
%
 
(In millions)
 
 
(In millions)
 
 
Total coal revenues
$
375.1

 
 
$
295.7

 
$
79.4

 
26.9
 %
Total non-coal revenues
9.6

 
 
26.6

 
(17.0
)
 
(63.9
)%
Coal sales revenue increased due to a 50.6% increase in tons sold which amounted to $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. Non-coal revenues decreased due to other miscellaneous revenue decreasing by $17.7 million due 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.
Cost and Expenses
 
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
 
$
 
%
 
(In millions)
 
 
(In millions)
 
 
Cost of coal revenues
$
307.0

 
 
$
258.6

 
$
48.4

 
18.7
 %
Depreciation, depletion and amortization
54.5

 
 
39.3

 
15.2

 
38.7
 %
Selling and administrative
17.1

 
 
20.5

 
(3.4
)
 
(16.6
)%
Cost of coal revenues increased due to an increase of 2.9 million in tons sold which increased cost of coal revenues $131.1 million. This increase was offset by a $9.73 per ton decrease in the cost to produce coal, or an aggregate $82.7 million.
Depreciation expense increased due 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 attributable to an increase in the depletion rate per ton.
Selling and administrative expenses decreased as 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 Original LTIP (defined as the long term incentive plant originally adopted in 2007 in connection with our formation and subsequently amended and restated in July 2010 in connection with our initial public offering) for the predecessor period ended December 31, 2014 and other cost reduction efforts. 

48

WESTMORELAND RESOURCE PARTNERS, LP AND SUBSIDIARIES

Nonoperating Results
 
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
 
$
 
%
 
(In millions)
 
 
(In millions)
 
 
Interest expense
$
(30.8
)
 
 
$
(27.8
)
 
$
(3.0
)
 
10.8
 %
Interest income
0.9

 
 

 
0.9

 
100 %

Gain on debt extinguishment

 
 
0.5

 
(0.5
)
 
(100
)%
Other income
0.3

 
 

 
0.3

 
100 %

Change in fair value of warrants
1.3

 
 
0.8

 
0.5

 
62.5
 %
Net loss attributable to noncontrolling interest

 
 
1.3

 
(1.3
)
 
(100
)%
Our interest expense increased $3.0 million due to the $120.0 million in additional debt incurred through the Kemmerer Drop on August 1, 2015. Our interest income in 2015 came from an increase in cash on hand. We incurred a $0.5 million gain on debt extinguishment for the predecessor period ended December 31, 2014 related to the forgiveness of a note. We recognized income from the change in fair value of warrants of $1.3 million. The increase is the result of the declining value of our units traded on the NYSE. Net loss attributable to noncontrolling interest relates to the 49% ownership interest in Harrison Resources owned by a subsidiary of Consol Energy through September 30, 2014.
Liquidity and Capital Resources 
We had the following liquidity at December 31, 2016 and 2015 :
 
December 31,
 
2016
 
2015
 
(In millions)
Cash and cash equivalents
$
15.1

 
$
3.7

Revolver
15.0

 
15.0

Total
$
30.1

 
$
18.7

Our business is capital intensive and requires substantial capital expenditures for, among other things, purchasing, maintaining and upgrading equipment used in developing and mining our coal, and acquiring reserves. Our principal liquidity needs are to finance current operations, replace reserves and fund capital expenditures, including costs of acquisitions from time to time, servicing of our debt and paying cash distributions to our unitholders when we are in a position to do so. Our primary sources of liquidity to meet these needs are cash generated by our operations and the limited remainder of our initial term loan borrowing under the 2014 Financing Agreement. Also, if we are able to sell the remaining excess Illinois Basin equipment, a large-capacity shovel and several smaller pieces of equipment, our liquidity will be enhanced. Additionally, selling our remaining coal reserves and/or facilities related to our Illinois Basin operations would further enhance our liquidity.
Our ability to satisfy our working capital requirements, meet debt service obligations, and fund planned capital expenditures substantially depends upon our future operating performance, which may be affected by prevailing economic conditions in the coal industry. To the extent our future operating cash flow or access to financing sources and the costs thereof are materially different than expected, our future liquidity may be adversely affected. We anticipate that our cash from operations, cash on hand and available borrowing capacity will be sufficient to meet our investing, financing, and working capital requirements for the foreseeable future.
Credit Facilities
See Note 13. Long-Term Debt to the consolidated financial statements for a description of our debt facilities. From time to time depending on market conditions and available cash, we intend to strategically repurchase our outstanding debt.

49

WESTMORELAND RESOURCE PARTNERS, LP AND SUBSIDIARIES

Historical Sources and Uses of Cash 
The following table reflects cash flows for the years indicated:
 
Westmoreland Resource Partners, LP
 
 
Oxford Resource Partners, LP
 
(Successor)(1)
 
 
(Predecessor)
 
For the Year Ended December 31,
 
Period of December 31,
 
 
Period from January 1 through December 31,
 
2016
 
2015
 
2014
 
 
2014
 
(In millions)
 
 
(In millions)
Net cash provided by (used in):
 
 
 
 
 
 
 
 
Operating activities
$
41.1

 
$
32.0

 
$
(1.8
)
 
 
$
24.4

Investing activities
(14.7
)
 
(134.9
)
 
0.1

 
 
(8.3
)
Financing activities
(15.0
)
 
100.6

 
7.7

 
 
(19.2
)
1 See Note 3. Acquisition And Pushdown Accounting to the consolidated financial statements.
Year Ended December 31, 2016 Compared to Year Ended December 31, 2015
Cash from operations increased $9.1 million to $41.1 million at December 31, 2016 from $32.0 million at December 31, 2015. The $9.1 million increase resulted from a $2.1 million decrease in net loss combined $7.0 million in favorable non-cash operating activity and $6.7 million favorable changes in working capital offset in part by $6.7 million unfavorable change in asset retirement obligation. The $7.0 million favorable change in non-chase operating activity primarily comprised of $10.7 million favorable change in impairment and restructuring charges, $2.7 million favorable change in non-cash interest expense and the amortization of deferred financing fees and $1.8 million in other non-cash charges offset in part by $4.3 million in unfavorable changes in depreciation, depletion and amortization expense and $3.9 million in unfavorable changes in loss on disposal and sale of assets. The $6.7 million favorable change in working capital primarily comprised a $6.1 million favorable change in deferred revenue compounded by a $5.2 million favorable change in accounts payable and accrued expenses, a $4.9 million favorable change in inventory and a $3.8 million favorable change in other assets and accrued liabilities, offset in part by a $11.9 million change in net receivables and a $1.4 million in accrued interest expense.
Cash used in investing activities decreased $120.2 million to $14.7 million at December 31, 2016 from $134.9 million at December 31, 2015. The decrease of $120.2 million was primarily due to $115.0 million in cash from the contribution of Westmoreland Kemmerer LLC in 2015 compounded by $4.1 million favorable change in additions to property, plant, equipment and other, $3.3 million favorable change in advance royalties payments and $0.7 million favorable change in net proceeds from the sales of assets, offset in part by a $2.9 million unfavorable change in restricted investments and bond collateral.
Cash used in financing activities decreased $115.6 million to $15.0 million<