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EX-32 - EXHIBIT 32 - WESTMORELAND COAL Coexh32_2015k.htm
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EX-31.1 - EXHIBIT 31.1 - WESTMORELAND COAL Coexh31-1_2015k.htm
EX-10.39 - EXHIBIT 10.39 - WESTMORELAND COAL Coexh1039_2015k.htm
EX-23.1 - EXHIBIT 23.1 - WESTMORELAND COAL Coexh23-1_2015k.htm
EX-21.1 - EXHIBIT 21.1 - WESTMORELAND COAL Coexh21-1_2015k.htm
EX-95.1 - EXHIBIT 95.1 - WESTMORELAND COAL Coexh95-1_2015k.htm
EX-10.47 - EXHIBIT 10.47 - WESTMORELAND COAL Coexh1047_2015k.htm
EX-10.37 - EXHIBIT 10.37 - WESTMORELAND COAL Coexh1037_2015k.htm

UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
 ______________________________________________________________
FORM 10-K
(Mark One)
x ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
For the fiscal year ended December 31, 2015
OR
 
¨ TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
For the transition period from                     to                     
Commission File No. 001-11155
  ______________________________________________________________
WESTMORELAND COAL COMPANY
(Exact name of registrant as specified in its charter)
Delaware
23-1128670
(State or other jurisdiction of
incorporation or organization)
(I.R.S. Employer
Identification No.)
 
 
9540 South Maroon Circle, Suite 200
Englewood, CO
80112
(Address of principal executive offices)
(Zip Code)
Registrant’s telephone number, including area code: (855) 922-6463
Securities registered pursuant to Section 12(b) of the Act:
 ______________________________________________________________­
Title of Each Class
 
Name of Exchange on Which Registered
Common Stock, par value $0.01 per share
 
NASDAQ Global Market

Indicate by check mark if the registrant is a well-known seasoned issuer, as defined in Rule 405 of the Securities Act.    Yes  ¨     No  x
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   x
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  x    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  x    No  ¨
Indicate by check mark if disclosure of delinquent filers pursuant to Item 405 of Regulation S-K (§229.405 of this chapter) 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 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.
Large accelerated filer
 
¨
Accelerated filer
 
x
 
 
 
 
 
Non-accelerated filer
 
¨  (Do not check if a smaller reporting company.)
Smaller reporting company
 
¨
Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Act).    Yes  ¨    No  x
The aggregate market value of voting common stock held by non-affiliates as of June 30, 2015 was $363,374,374.
There were 18,307,350 shares outstanding of the registrant’s common stock, $0.01 par value per share (the registrant’s only class of common stock), as of March 9, 2016.
  ______________________________________________________________

DOCUMENTS INCORPORATED BY REFERENCE
Portions of the Definitive Proxy Statement on Schedule 14A to be filed within 120 days after December 31, 2015, in connection with the Company’s 2016 Annual Meeting of Stockholders scheduled to be held on May 17, 2016, are incorporated by reference into Part III of this Annual Report on Form 10-K.



WESTMORELAND COAL COMPANY
FORM 10-K
ANNUAL REPORT
TABLE OF CONTENTS
 
Item
 
Page
 
 
 
 
 
1
1A
1B
2
3
4
 
 
 
 
 
5
6
7
7A
8
9
9A
 
 
 
 
 
10
11
12
13
14
 
 
 
 
 
15

2


Cautionary Note Regarding Forward-Looking Statements
This Annual Report on Form 10-K contains “forward-looking statements.” Forward-looking statements can be identified by words such as “anticipates,” “intends,” “plans,” “seeks,” “believes,” “estimates,” “expects” and similar references to future periods. Examples of forward-looking statements include, but are not limited to, statements we make throughout this report regarding recent acquisitions and their anticipated effects on us, and statements in “Management’s Discussion and Analysis of Financial Condition and Results of Operations — Significant Anticipated Variances Between 2015 and 2016 and Related Uncertainties” regarding factors that may cause our results of operation in future periods to differ from our expectations.
Forward-looking statements are based on our current expectations and assumptions regarding our business, the economy and other future conditions. Because forward-looking statements relate to the future, they are subject to inherent uncertainties, risks and changes in circumstances that are difficult to predict. Our actual results may differ materially from those contemplated by the forward-looking statements. We therefore caution you against relying on any of these forward-looking statements. They are statements neither of historical fact nor guarantees or assurances of future performance. Important factors that could cause actual results to differ materially from those in the forward-looking statements include political, economic, business, competitive, market, weather and regulatory conditions and the following: 
Our ability to effectively manage the San Juan Entities following the San Juan Acquisition (each as defined below);
Our ability to effectively manage Westmoreland Resource Partners, LP ("WMLP");
Our substantial level of indebtedness and our ability to adhere to financial covenants related to our borrowing arrangements;
Changes in our post-retirement medical benefit and pension obligations and the impact of the recently enacted healthcare legislation on our employee health benefit costs;
Inaccuracies in our estimates of our coal reserves;
The effect of consummating financing, acquisition or disposition transactions;
 Our potential inability to expand or continue current coal operations due to limitations in obtaining bonding capacity for new mining permits, and/or increases in our mining costs as a result of increased bonding expenses;
The effect of prolonged maintenance or unplanned outages at our operations or those of our major power generating customers;
The inability to control costs, recognize favorable tax credits and/or receive adequate train traffic at our open market mine operations;
Our efforts to effectively integrate Prairie Mines & Royalty ULC and Coal Valley Resources Inc. (the "Canadian Acquisition"), which were amalgamated as of January 1, 2016, with our existing business and our ability to manage our expanded operations following the Canadian Acquisition;
Our ability to realize growth opportunities and cost synergies as a result of the addition of our Canadian operations;
The ability of our hedging arrangement with respect to our Roanoke Valley Power Facility ("ROVA") to generate free cash flow due to the fully hedged position through March 2019;
Competition within our industry and with producers of competing energy sources;
Our relationships with, and other conditions affecting, our customers;
The availability and costs of key supplies or commodities, such as diesel fuel, steel 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 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 ("GHGs");
The effect of the Environmental Protection Agency’s ("EPA") and Canadian and provincial governments’ inquiries and regulations affecting operations of the power plants to which we provide coal; and

3


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


4


PART I
The words “we,” “our,” “the Company,” or “Westmoreland,” as used in this report, refer to Westmoreland Coal Company and its subsidiaries.

ITEM 1
BUSINESS.
Overview
Westmoreland Coal Company began mining in Westmoreland County, Pennsylvania in 1854 as a Pennsylvania corporation. In 1910, we incorporated in Delaware and continued our focus on coal operations in Pennsylvania and the Appalachian Basin. We moved our headquarters from Philadelphia, Pennsylvania to Colorado Springs in 1995 and relocated the headquarters to Englewood, Colorado in November 2011.
Today, Westmoreland Coal Company is an energy company employing approximately 3,248 employees. We conduct our operations through our subsidiaries and our principal sources of cash are distributions from our operating subsidiaries. At December 31, 2015, our operations included 12 wholly-owned coal mines in the U.S. and Canada, a char production facility, a 50% stake in an activated carbon plant, and two coal-fired power generation units. We also own the general partner of, and 93.8% of the total equity interest in,WMLP, which is a publicly traded limited partnership that owns and operates five mining complexes in Ohio and one mine in Wyoming. We sold 53.3 million tons of coal in 2015.
We classify our business into six segments: Coal - U.S., Coal - Canada, Coal - WMLP, Power, Heritage, and Corporate. Our principal operating segments are our Coal - U.S., Coal - Canada, Coal - WMLP and Power segments. Our two non-operating segments are our Heritage and Corporate segments. Our Heritage segment primarily includes the costs of benefits we provide to former mining operation employees, and our Corporate segment consists primarily of corporate administrative expenses and business development expenses. In addition, the Corporate segment contains our captive insurance company, Westmoreland Risk Management Inc. (“WRM”), through which we have elected to retain some of our operating risks.
We produce and sell thermal coal primarily to investment grade utility customers under long-term cost-protected contracts, as well as to industrial customers and barbeque briquettes manufacturers. With the exception of the San Juan mine and the Buckingham mine, each of which are underground mines, our focus is on mine locations where we can employ dragline surface mining methods. We have extensive operational experience in dragline surface mining and this mining method has historically had predictable and consistent costs and production rates. In addition, we focus on mine locations that allow us to take advantage of close customer proximity through mine-mouth power plants and strategically located rail transportation, with the goal of being the low-cost supplier of choice to the customers that we serve. We believe this business model has contributed to the stability of our cash flows and results of operations.
At December 31, 2015, our U.S. coal operations were located in Montana, North Dakota, Texas and Ohio. Following the San Juan Acquisition in January of 2016, we expanded our U.S. coal operations to include New Mexico. Our Canadian coal operations are located in Alberta and Saskatchewan. Our WMLP coal operations are in Ohio and Wyoming. We also operate two coal-fired power generating units in North Carolina with a total capacity of approximately 230 megawatts.
The following chart provides an overview of the current operating subsidiaries that compose our coal and power segments and our relationship to each of them as of the filing date of this report, unless otherwise noted. The entities shaded in dark grey represent the “Restricted Group”, and the unshaded entities represent the “Unrestricted Group” for the purposes of certain of our debt agreements and instruments, described in further detail in Item 7 - Management’s Discussion and Analysis of Financial Condition and Results of Operations and also at Note 8 - Lines Of Credit And Long-Term Debt to our consolidated financial statements:

5


(1) The San Juan Acquisition closed on January 31, 2016
(2) As of January 1, 2016 Coal Valley Resources Inc. was amalgamated with Prairie Mines & Royalty ULC
(3) As WMLP's general partner, we are entitled to incentive distribution rights (IDR)
As of December 31, 2015, our long-term debt consisted of (i) $350 million in principal amount of our 8.75% senior secured notes due 2022 (“8.75% Notes” or “Indenture”) and (ii) a $327 million principal balance on our term loan maturing in 2020 (“WCC Term Loan Facility”). Additionally, availability under the our revolving line of credit (“WCC Revolving Credit Facility”) was $28.2 million with an outstanding balance of $19.8 million supporting letters of credit and $2.0 million drawn on the WCC Revolving Credit Facility. Refer to the information regarding the revenues, operating income and total assets of each of our segments for the years ended December 31, 2015, 2014 and 2013 contained in Note 19 - Business Segment Information to our consolidated financial statements.
Debt Facility
WMLP has a $295 million credit facility (the “WMLP Term Loan Facility”) that is governed by a Financing Agreement among Oxford Mining Company, LLC (“Oxford”), WMLP and certain of its subsidiaries as guarantors, the lenders party thereto and U.S. Bank National Association as administrative and collateral agent (the “WMLP Financing Agreement”). The WMLP Term Loan Facility consists of an initial $175 million term loan and an option for an additional $120 million in term loans for acquisitions which was exercised on August 1, 2015 to finance the Kemmerer Drop. The WMLP Term Loan Facility matures in December 2018 and the WMLP Financing Agreement contains customary financial and other covenants. It also permits distributions to WMLP’s unitholders under specified circumstances. Borrowings under the WMLP Financing Agreement are secured by substantially all of WMLP’s and its subsidiaries’ assets.
2015 Transactions
Buckingham Acquisition
On January 1, 2015, we acquired Buckingham Coal Company, LLC (“Buckingham”), an Ohio-based coal supplier, for a total cash purchase price of $32.5 million. Separately, an affiliate of Westmoreland entered into a five-year coal supply agreement with AEP Generation Resources Inc. (“AEP”), which includes an obligation to purchase a minimum of 5.5 million tons of coal. In connection with this acquisition, we amended the WCC Term Loan Facility to increase the principal amount by $75.0 million, for an aggregate principal WCC Term Loan Facility amount of $425 million as of January 22, 2015.

6


Buckingham conducts underground room and pillar mining operations in Ohio. Buckingham is strategically located near WMLP's New Lexington complex, which has access to the Norfolk Southern rail system and a state-of-the-art preparation plant strategically located for efficient rail and river transportation for both Buckingham and WMLP coal. We expect Buckingham's proximity to WMLP’s New Lexington complex to allow for substitute tonnage to be supplied by WMLP to AEP when it is economically advantageous to do so.
Kemmerer Drop
Effective August 1, 2015, we contributed 100% of the outstanding equity interests in Westmoreland Kemmerer, LLC (“Kemmerer”), which owns and operates the Kemmerer Mine in Lincoln County, Wyoming, to WMLP in exchange for $230 million in aggregate consideration, composed of $115 million of cash and $115 million in newly issued WMLP Series A Convertible Units (the “Series A Units” and such transaction, the “Kemmerer Drop”). In connection with the Kemmerer Drop, all employees of Kemmerer and related employee liabilities, including but not limited to post-retirement pension obligations and post-retirement health benefits, were transferred to us.The Series A Units are convertible into common units representing limited partner interests of WMLP (“Common Units”), on a one-for-one basis, upon the earlier of (i) the date on which WMLP first makes a regular quarterly cash distribution to holders of Common Units in an amount equal to at least $0.22 per Common Unit, or (ii) a change of control of WMLP. Following the Kemmerer Drop, we hold a 93.8% interest in WMLP (on a fully diluted basis).
WCC Revolving Credit Facility Amendment
On June 2, 2015, we amended the WCC Revolving Credit Facility to permit Westmoreland and the other U.S. borrowers thereunder to borrow up to an additional $25.0 million between June 15th and August 15th of each year. As a result, the U.S. sub-facility has a maximum available borrowing amount of $55.0 million during these periods, and the Canadian sub-facility has a maximum available borrowing amount of $20.0 million yielding a total aggregate borrowing capacity of $75.0 million. Outside of these periods, the WCC Revolving Credit Facility has a maximum available borrowing amount of $50.0 million.
WMLP Revolving Credit Facility
On October 23, 2015, WMLP and its subsidiaries entered into a revolving credit facility with the lenders party thereto and The PrivateBank and Trust Company, as administrative agent (the “WMLP Revolving Credit Facility”). The WMLP Revolving Credit Facility permits borrowings up to the aggregate principal amount of $15.0 million and permits letters of credit in an aggregate outstanding amount of up to $10.0 million, which reduces availability under the WMLP Revolving Credit Facility on a dollar-for-dollar basis. At December 31, 2015, availability under the WMLP Revolving Credit Facility was $15.0 million with no outstanding balance or supporting letters of credit.
Recent Developments

On January 31, 2016, Westmoreland San Juan, LLC (“WSJ”), a special purpose subsidiary of Westmoreland, acquired San Juan Coal Company (“SJCC”), which operates the San Juan mine in Farmington, New Mexico, and San Juan Transportation Company (together with SJCC, the “San Juan Entities” and such transaction, the “San Juan Acquisition”) for a total cash purchase price of approximately $127 million, subject to post-closing adjustments. The San Juan mine is the exclusive supplier of coal to the adjacent San Juan Generating Station (“SJGS”) under a coal supply agreement with tonnage and pricing adjusting quarterly through 2022.

WSJ financed the San Juan Acquisition with a $125 million loan from NM Capital Utility Corporation, an affiliate of Public Service Company of New Mexico (one of the owners of SJGS), and with available cash on hand. The loan is structured as a senior secured term loan (the “San Juan Loan”) maturing February 1, 2021 and is expected to bear interest at a (i) 7.25% rate (the “Margin Rate”) plus (ii) (A) the London Interbank Offered Rate for a three month period plus (B) a statutory reserve rate, which such Margin Rate increases incrementally during each year of the Loan term. The Loan has no prepayment penalties. The agreements governing the Loan include representations and warranties and covenants regarding the ownership and operation of SJCC and the properties acquired in the Acquisition and standard special purpose bankruptcy remote entity covenants designed to preserve the separateness from Westmoreland of each of (i) WSJ, (ii) its direct parent company, Westmoreland San Juan Holdings, Inc., and (iii) the San Juan Entities ((i), (ii) and (iii) collectively, the “Westmoreland San Juan Entities”). Obligations under the Loan are recourse only to the Westmoreland San Juan Entities and their assets and neither Westmoreland nor its subsidiaries (other than the Westmoreland San Juan Entities) is an obligor under the Loan in any respect. The agreement governing the Loan requires that all revenues of the San Juan Entities, aside from payments on certain leases, are deposited into a cash management collection account swept monthly for operating expenses, capital expenditures, and Loan payment and prepayment.  


7


In connection with certain mining permits relating to the operation of the San Juan mine, WSJ is required to post reclamation bonds of $162 million with the New Mexico Mining and Minerals Division. In order to facilitate the posting of reclamation bonds by Zurich American Insurance Company (“Zurich”) on behalf of WSJ, PNM Resources, Inc. (“PNM”), Westmoreland and SJCC entered into a Reclamation Bond Agreement (the “Reclamation Bond Agreement”) with Zurich.
The following map shows our operations, as of the date of this filing, including the operations under our control following the San Juan Acquisition:
Coal Segments
General
Our Coal - U.S. and Coal - Canada Segments focus on niche coal markets where we take advantage of customer proximity and strategically located rail transportation. We sell substantially all of the coal that we produce to power generation facilities. The close proximity of our mines and coal reserves to our customers reduces transportation costs and, we believe, provides us with a significant competitive advantage with respect to retention of those customers. Ten of our 12 mines are in very close proximity to the customer’s property, with economical delivery methods that include, in several cases, conveyor belt delivery systems linked to the customer’s facilities. We typically enter into long-term, cost-protected supply contracts with our customers that range from approximately one to 40 years. Our current coal sales contracts have a weighted average remaining term of 15 years. For the twelve months ended December 31, 2015, substantially all of our tons of coal sold were sold under long-term contracts. We employ a rigorous capital spending and maintenance philosophy and believe our equipment is well maintained.
Properties
Across all our coal operating segments (Coal - U.S., Coal - Canada and Coal - WMLP), we owned or controlled an estimated 1,222 million tons of total proven or probable coal reserves as of December 31, 2015, including 145 million tons of proven or probable coal reserves held by WMLP.

8


Substantially all of our properties and assets in the Coal - U.S. Segment and Coal - Canada Segment are encumbered by liens securing our and our subsidiaries’ outstanding indebtedness. Specifically, the holders of the 8.75% Notes and the lenders under the WCC Term Loan Facility hold first priority liens, on a pari passu basis, on substantially all of our and our wholly owned subsidiaries’ tangible and intangible assets (excluding certain equity interests, mineral rights and sales contracts and certain assets subject to existing liens). In addition, borrowings under the WCC Revolving Credit Facility are secured by first priority liens on our and our wholly owned subsidiaries accounts receivable, inventory and certain other specified assets. The assets of WMLP are encumbered by separate liens securing the indebtedness of WMLP and its subsidiaries and are not part of the collateral with respect to the 8.75% Notes, the WCC Term Loan Facility or the WCC Revolving Credit Facility.
The following table provides information about mines we owned or controlled as of December 31, 2015:
 
Coal - U.S.
 
Coal - Canada
 
Coal - WMLP(2)
 
Total
 
(In thousands of tons)
Coal reserves:(1)
 
 
 
 
 
 
 
     Proven
359,063

 
593,605

 
128,788

 
1,081,456

     Probable
17,078

 
107,053

 
16,436

 
140,567

Total proven and probable reserves
376,141

 
700,658

 
145,224

 
1,222,023

Permitted reserves
184,320

 
622,152

 
58,896

 
865,368

2015 production
21,808

 
23,241

 
8,481

 
53,530

____________________
(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)
Represents total reserve information for WMLP, of which we are the general partner and owner of 93.8% of the total outstanding equity interests.

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The following table provides summary information regarding our principal mining operations as of December 31, 2015:
Mining
Operation
 
Prior 
Operator
 
Manner of
Transport
 
Machinery
 
Tons Sold
(In thousands)
 
Total Cost
of Property,
Plant and
Equipment
($ in millions)
 

Employees/Labor Relations (1)
 
Coal Seam
2013
 
2014
 
2015
 
 
 
Coal - U.S. Segment
Montana
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Colstrip
 
Entech, Inc., a subsidiary of Montana Power, Purchased 2001
 
Ÿ  Conveyor
    belt
Ÿ  BNSF Rail
Ÿ  Truck
 
Ÿ  4 dragline 
Ÿ  Load-out
    facility
 
8,234

 
9,018

 
9,626

 
$
202.8

 
393 employees
312 represented  by Local 400 of the IUOE
 
Ÿ  Rosebud
Absaloka
 
Washington 
Group International, Inc. as contract operator, Ended contract in 2007
 
Ÿ  BNSF Rail 
Ÿ  Truck
 
Ÿ  1 dragline 
Ÿ  Load-out
    facility
 
4,168

 
6,557

 
5,844

 
$
167.7

 
174 employees
141 represented by Local 400 of the IUOE
 
Ÿ  Rosebud - McKay
Savage
 
Knife River Corporation, a subsidiary of MDU Resources Group, Inc., Purchased 2001
 
Ÿ  Truck
 
Ÿ  1 dragline
 
350

 
332

 
271

 
$
9.7

 
13 employees
10 represented by Local 400 of the IUOE
 
Ÿ  Pust
Texas
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Jewett
 
Entech, Inc., a subsidiary of Montana Power, Purchased 2001
 
Ÿ  Conveyor
    belt
 
Ÿ  4 draglinesŸ  Shovel
 
5,015

 
5,255

 
3,357

 
$
31.8

 
279 employees
 
Ÿ  Wilcox
    Group
North Dakota
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Beulah
 
Knife River Corporation, a subsidiary of MDU Resources Group, Inc., Purchased 2001
 
Ÿ  Conveyor
    belt
Ÿ  BNSF Rail
 
Ÿ  1 dragline
Ÿ  Load-out
    facility
 
2,521

 
2,731

 
2,136

 
$
66.6

 
119 employees
99 represented by Local 1101 of the UMWA
 
Ÿ  School-
house
Ÿ  Beulah-Zap
Ohio
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Buckingham (2)
 
Clay & Bryan Graham purchased 2015
 
Ÿ  Ohio Central & Norfolk Southern Rail 
Ÿ  Truck
 
Ÿ  Load-out
    facility
Ÿ  Prep plant
Ÿ  8 continuous Miners
 

 

 
1,246

 
$
42.6

 
277 employees
 
Ÿ  Middle Kittanning
TOTALS Coal - U.S. Segment
 
 
20,288

 
23,893

 
22,480

 
$
521.2

 
1,255 employees (562 union)

10


Mining
Operation
 
Prior 
Operator
 
Manner of
Transport
 
Machinery
 
Tons Sold
(In thousands) (3)
 
Total Cost
of Property,
Plant and
Equipment
($ in millions)
 
Employees/Labor Relations
(1)
 
Coal Seam
2013
 
2014
 
2015
 
 
 
Coal - Canada Segment
Alberta
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Paintearth
 
Sherritt International Corporation
 
Ÿ  Haul Trucks
 
Ÿ  2 draglines
Ÿ  Cat 993 FEL, Euclid CH160 haulers
 

 
1,950

 
1,972

 
$
20.1

 
80 employees
65 represented by IUOE
 
Ÿ  Battle River, Paintearth
Genesee
 
Sherritt International Corporation
 
Ÿ  Haul Trucks
 
Ÿ  2 draglines
Ÿ  Cat 789, Komatsu 830E, P&H 4100, haulers
 

 
3,621

 
5,745

 
$
42.1

 
130 employees
 
Ÿ  Ardley Coal Zone
Sheerness
 
Sherritt International Corporation
 
Ÿ  Haul Trucks
 
Ÿ  2 draglines
Ÿ  Cat 993 FEL, Cat 776 haulers
 

 
2,490

 
3,078

 
$
31.3

 
105 employees
86 represented by IUOE
 
Ÿ  Sunnynook, Sheerness
Coal Valley
 
Sherritt International Corporation
 
Ÿ  Rail
 
Ÿ  3 draglines
Ÿ  shovels and end dump trucks
 

 
2,022

 
2,160

 
$
38.1

 
314 employees
250 represented by IOUE
 
Ÿ  Val D'Or, Arbour, Mynheer
Saskatchewan
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Poplar River
 
Sherritt International Corporation
 
Ÿ  Rail
 
Ÿ  2 draglines
Ÿ  FEL, tractor trailer haulers
 

 
2,617

 
3,595

 
$
34.0

 
156 employees
134 represented by IBEW
3 by Unifor
 
Ÿ  Willow Bunch
Estevan
 
Sherritt International Corporation
 
Ÿ  Haul Trucks
 
Ÿ  6 draglines
Ÿ  FEL and tractor trailer haulers
 

 
3,705

 
6,370

 
$
110.8

 
364 employees
292 represented by UMWA
 
Ÿ  Souris River, Roche Percee, Estevan
TOTALS Coal - Canada Segment
 
 

 
16,405

 
22,920

 
$
276.4

 
1,149 employees (830 union)

11


Mining
Operation
 
Prior 
Operator
 
Manner of
Transport
 
Machinery
 
Tons Sold
(In thousands) (2)
 
Total Cost
of Property,
Plant and
Equipment
($ in millions)
 
Employees/Labor Relations
(1)
 
Coal Seam
2013
 
2014
 
2015
 
 
 
Coal - WMLP Segment
Ohio - Oxford
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
New Lexington
 
Oxford Resource Partners, LP, purchased 2014
 
Rail
 
Coal crusher with truck scale, rail load-out
 
 
 
See (4)
 
See (4)
 
See (4)
 
58
 
Lower Kittanning #5. Middle Kittanning #6
Tuscarawas
 
Oxford Resource Partners, LP, purchased 2014
 
Truck
 
2 coal crushers with truck scales, 2 blending facilities, 1 preparation plant
 
 
 
See (4)
 
See (4)
 
See (4)
 
62
 
Brookville #4,Lower Kittanning #5, Middle Kittanning #6, Upper Freeport #7 Mahoning #7A
Belmont
 
Oxford Resource Partners, LP, purchased 2014
 
Barge
 
Coal crusher and blending facility
 
 
 
See (4)
 
See (4)
 
See (4)
 
51
 
Pittsburgh #8, Meigs Creek #9
Noble
 
Oxford Resource Partners, LP, purchased 2014
 
Barge, Truck
 
Coal crusher and blending facility
 
 
 
See (4)
 
See (4)
 
See (4)
 
 
Pittsburgh #8, Meigs Creek #9
Cadiz
 
Oxford Resource Partners, LP, purchased 2014
 
Barge, Rail, Truck
 
3 coal crushers with truck scales, rail load-out
 
 
 
See (4)
 
See (4)
 
See (4)
 
195
 
Pittsburgh #8, Redstone #8A,Meigs Creek #9
SUBTOTAL Ohio Oxford (6)
 
 
 
 
 
 
 
5,631

 
3,463

 
$
211.4

 
366
 
 
Wyoming
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Kemmerer
 
Chevron Mining Inc., Purchased 2012
 
Conveyor belt,
Rail, Truck
 
Truck and shovel
 
4,639

 
4,399

 
4,471

 
$
151.3

 
292 employees 231 represented by UMWA (5)
 
 
TOTALS Coal - WMLP Segment
 
 
4,639

 
10,030

 
7,934

 
$
362.7

 
658 employees (231 union)
___________________
(1)
The total number of employees for the Ohio - Oxford mining complexes does not include 39 non-union employees located at administrative offices nor does it include 76 non-union employees located at mine support facilities.
(2)
WCC acquired the GP of WMLP on December 31, 2014, therefore, historical tonnage for 2013 is not applicable to the Ohio - Oxford mines.
(3)
The Tusky, Plainfield and Muhlenberg mine complexes were inactive during 2015, therefore, their individual statistics are not presented.
(4)
As the Oxford mining complexes sell their coal from centralized coal pits, breaking tons sold and PP&E out by mine is not meaningful. Therefore, the table above shows the Ohio - Oxford mine's tons sold and PP&E in total.
(5)
The labor agreement at the Kemmerer Mine expires in 2018.

Coal - U.S. Segment Properties
Our Coal - U.S. Segment is composed of our wholly owned mines located in the United States. Mines in our Coal - U.S. Segment control coal reserves and deposits through long-term leases. Our Coal - U.S. Segment owned or controlled an estimated 376.1 million tons of total proven or probable coal reserves as of December 31, 2015. Montana, Texas, and North Dakota each use a permitting process approved by the Office of Surface Mining. Mines in our Coal - U.S. Segment have chosen to permit coal reserves on an incremental basis and given the current rates of mining and demand, have sufficient permitted coal to meet production for the periods shown in the table below. We secure all of our final reclamation obligations by reclamation bonds as required by the respective state agencies. We perform contemporaneous reclamation activities at each mine in the normal course of operations and coal production.

The following table provides information about mines in our Coal - U.S. Segment as of December 31, 2015:

12


Coal - U.S.
Absaloka
Mine
 
Colstrip
Mine
 
Jewett
Mine
 
Beulah
Mine
 
Savage
Mine
 
Buckingham Mine
Total
Owned by
Westmoreland
Resources, Inc.
 
Western
Energy
Company
 
Texas
Westmoreland
Coal Co.
 
Dakota
Westmoreland
Corporation
 
Westmoreland
Savage
Corporation
 
Buckingham Coal Company, LLC
 
Location
Big Horn
County, MT
 
Rosebud and
Treasure
Counties, MT
 
Leon, 
Freestone
and Limestone
Counties, TX
 
Mercer and
Oliver
Counties, ND
 
Richland
County, MT
 
Perry County, OH
 
Proven coal reserves
(thousands of tons)
36,061

 
258,977

 
22,888

 
20,689

 
4,246

 
16,202

359,063

Probable coal reserves
(thousands of tons)

 

 

 
15,516

 

 
1,562

17,078

Total proven & probable reserves (thousands of tons)
36,061

 
258,977

 
22,888

 
36,205

 
4,246

 
17,764

376,141

Permitted reserves
(thousands of tons)
36,061

 
90,859

 
22,888

 
12,681

 
4,246

 
17,585

184,320

2015 production
(thousands of tons)
5,882

 
9,414

 
3,357

 
2,133

 
270

 
752

21,808

Estimated life of permitted
reserves (1)
2021

 
2024

 
2020

 
2017

 
2028

 
2032

 
 Lessor
Ÿ  Crow Tribe
Ÿ  Private parties
 
Ÿ  Federal Government
Ÿ  State of MT
Ÿ  Great Northern Properties
 
Ÿ  Private parties
 
Ÿ  Private parties
Ÿ  State of ND
Ÿ  Federal Government
 
Ÿ  Private parties
Ÿ  Federal Government
 
Ÿ  Private parties
Ÿ  State of OH
Ÿ  AEP
Ÿ  BCC ownership
 
Lease term
Through
exhaustion
 
Varies
 
Varies
 
Varies
 
Varies
 
Varies
 
Current production capacity
(thousands of tons)
7,500

 
13,300

 
7,000

 
3,400

 
400

 
1,100

 
Coal type
Sub-bituminous
 
Sub-bituminous
 
Lignite
 
Lignite
 
Lignite
 
Bituminous
 
Major customers
Ÿ  Xcel Energy
 
Ÿ  Western
Fuels Assoc.
 
Ÿ  Midwest Energy
 
Ÿ  Rocky Mountain Power

Ÿ  Trans Alta
 
Ÿ  Colstrip 1&2 owners, Colstrip 3&4 owners
 
Ÿ  NRG Texas Power LLC
 
Ÿ  Otter Tail
 
Ÿ  MDU
 
Ÿ  Northern Municipal Power Agency
 
Ÿ  Northwestern Energy
 
Ÿ  MDU
 
Ÿ  Sidney Sugars
 
Ÿ  American Electric Power
 
Ÿ  Glatfelter
 
Delivery method
Truck, rail
 
Conveyor, truck, rail
 
Conveyor
 
Conveyor, rail
 
Truck
 
Rail
 
Approx. heat content (BTU/lb.) (2)
8,535

 
8,414

 
6,675

 
7,090

 
6,634

 
11,600

 
Approx. sulfur content (%) (3)
0.64

 
0.66

 
0.90

 
0.66

 
0.55

 
2.00

 
Year current complex opened
1974

 
1968

 
1985

 
1963

 
1958

 
2007

 
Total tons mined since inception (thousands of tons)
197,511

 
474,870

 
205,339

 
112,099

 
16,995

 
10,310

 
 ____________________
(1)
Approximate year in which permitted reserves would be exhausted, based on current mine plan and production rates. The Jewett Mine’s reserves are covered under two separate mining permits, which must be renewed every five years.
(2)
Approximate heat content applies to the coal mined in 2015.
(3)
Approximate sulfur content applies to the tons mined in 2015.
With the exception of the Jewett mine, where we control some reserves through fee ownership, we lease all of our coal properties in our Coal - U.S. Segment. We are a party to coal leases with the federal government, state governments, and private parties at our Absaloka, Colstrip, Beulah, Savage and Jewett Mines. Each of the federal and state government leases continue indefinitely provided there is diligent development of the property and continued operation of the related mines. Federal statute generally sets production royalties on federal leases at 12.5% of the gross proceeds of coal mined and sold for surface mines. Our private leases are generally long-term and have options for renewal. We believe that we have satisfied all lease conditions in order to retain the properties and keep the leases in place.
We are a party to two leases with the Crow Tribe covering 18,406 acres of land at our Absaloka Mine, which are held by our wholly owned subsidiary, Westmoreland Resources, Inc. (“WRI”). In 2008, and in order to take advantage of certain

13


Indian Coal Tax Credits (“ICTC”) for the production of coal on the leased Crow Tribe land, WRI entered into a series of transactions, including the formation of Absaloka Coal, LLC with an unaffiliated partner. As part of such transaction, WRI subleased its leases with the Crow Tribe to Absaloka Coal, LLC, granting it the right to mine specified quantities of coal with WRI as contract miner. From 2009 through 2013, we experienced a yearly average of $3.1 million of income and $6.1 million of cash receipts from the ICTC. On December 18, 2015, the ICTC was extended for two years through December 31, 2016 as part of H.R. 2029 - the Consolidated Appropriations Act 2016. We plan to pursue monetization of this tax credit in the future if possible.
Coal - Canada Segment Properties
Mines in our Coal - Canada Segment owned or controlled an estimated 700.7 million tons of total proven or probable coal reserves as of December 31, 2015. In 2015 we conducted our Canadian coal operations through Coal Valley Resources Inc. which operated our Coal Valley Mine and Prairie Mines & Royalty ULC which operated the mines comprising our Prairie Operations. On January 1, 2016 Coal Valley Resources Inc. and Prairie Mines & Royalty ULC were amalgamated with the resulting entity continuing under the name Prairie Mines & Royalty ULC. Mines in our Coal - Canada Segment control coal reserves and deposits through a combination of long-term Crown or third-party leases or through fee ownership. The majority of our Prairie Operation’s coal production is sold to Canadian utilities for electricity production, and all of our Prairie Operation’s five mines are mine mouth operations (where our mine is adjacent to the customer’s plant). The Coal Valley Mine produces thermal coal which is exported primarily to the Asia-Pacific market via rail and ocean vessel under reserved port capacity. Our Canadian operations are located in Alberta and Saskatchewan and our mines are permitted in accordance with the legislation in effect in those Provinces. We secure all of our final reclamation obligations by reclamation bonds as required by the respective provincial agencies. We perform contemporaneous reclamation activities at each mine in the normal course of operations and coal production.
The following table provides information about mines in our Coal - Canada Segment as of December 31, 2015:
Coal - Canada
Paintearth
 
Genesee
 
Sheerness
 
Poplar River
 
Coal Valley
 
Estevan
 
Total
Owned by
Prairie Mines & Royalty ULC
 
Prairie Mines & Royalty ULC
 
Prairie Mines & Royalty ULC
 
Prairie Mines & Royalty ULC
 
Coal Valley Resources Inc.
 
Prairie Mines & Royalty ULC
 
 
Location
Forestburg, AB
 
Warburg, AB
 
Hanna, AB
 
Coronach, SK
 
Edson, AB
 
Estevan, SK
 
 
Proven Coal reserves
(thousands of tons)
20,375

 
254,118

 
30,762

 
100,078

 
8,750

 
179,522

 
593,605

Probable Coal reserves
(thousands of tons)

 
41,880

 
3,504

 
7,108

 
5,900

 
48,661

 
107,053

Total proven and probable reserves (thousands of tons)
20,375

 
295,998

 
34,266

 
107,186

 
14,650

 
228,183

 
700,658

Permitted reserves
(thousands of tons)
20,375

 
295,998

 
34,266

 
80,372

 
8,750

 
182,391

 
622,152

2015 production
(thousands of tons)
1,997

 
5,745

 
3,107

 
3,694

 
2,133

 
6,565

 
23,241

Estimated life of permitted
reserves(1)
2023

 
2067

 
2025

 
2036

 
2020

 
2046

 
 
 Lessor/Ownership
Ÿ  Private parties
Ÿ  Provincial Government
Ÿ  Freehold
 
Ÿ  Private parties
Ÿ  Provincial Government
Ÿ  Freehold
 
Ÿ  Private parties
Ÿ  Provincial Government
Ÿ  Freehold
 
Ÿ  Private parties
Ÿ  Provincial Government
Ÿ  Freehold
 
Ÿ  Private parties
Ÿ  Provincial Government
Ÿ  Freehold
 
Ÿ  Private parties
Ÿ  Provincial Government
Ÿ  Freehold
 
 
Lease term
Varies
 
Varies
 
Varies
 
Varies
 
Varies
 
Varies
 
 
Current production capacity
(thousands of tons)
3,280

 
5,745

 
3,638

 
4,100

 
4,000

 
6,400

 
 
Coal type
Sub-bituminous
 
Sub-bituminous
 
Sub-bituminous
 
Lignite
 
Bituminous
 
Lignite
 
 
Major customers
Ÿ  ATCO Power
 
Ÿ  Capital Power
 
Ÿ  ATCO Power/TransAlta Corporation
 
Ÿ  Sask Power
 
Ÿ  Asian and domestic customers
 
Ÿ  Sask Power
 
 
Delivery method
Haul trucks
 
Haul trucks
 
Haul trucks
 
Rail
 
Rail
 
Haul trucks
 
 
Approx. heat content
(BTU/lb.)(2)
7,583

 
8,398

 
7,249

 
5,773

 
10,800

 
6,724

 
 
Approx. sulfur content (%)(3)
0.43

 
0.19

 
0.50

 
<.99

 
0.30

 
0.40

 
 
Year current complex opened
1956

 
1988

 
1984

 
1978

 
1978

 
1973

 
 
Total tons mined since inception (thousands of tons)
153,637

 
115,515

 
92,062

 
129,927

 
177,339

 
164,756

 
 
____________________
(1)
Approximate year in which permitted reserves would be exhausted, based on current mine plan and production rates.
(2)
Approximate heat content applies to the coal mined in 2015.
(3)
Approximate sulfur content applies to the coal mined in 2015.
Coal reserves and leases in Canada are generally under the jurisdiction of provincial governments. Coal producers, including Westmoreland, gain access to their coal reserves through provincial Crown coal leases, freehold ownership or third party leases or subleases. Coal reserves for our Canadian Operations are held by all three methods, the mix of which varies from mine to mine.
Alberta Crown coal leases are granted under the Mines and Minerals Act (Alberta) for terms of 15 years. The leases are renewable for further terms of 15 years each, subject to the Mines and Minerals Act (Alberta) and the regulations in force at the time of renewal, and, in the case of any particular renewal, to any terms and conditions prescribed by order of the Minister of Energy. Crown coal royalties are set by the Coal Royalty Regulation (Alberta). Under this regulation, there are two royalty regimes. The royalty rate for Crown-owned sub-bituminous coal is $0.55 per tonne, which is roughly equivalent to $0.50 per ton. The royalty rate for Crown-owned bituminous coal, which is based on a revenue less cost regime, is 1% of mine mouth revenue prior to mine payout, plus an additional 13% of net revenue after mine payout. No provincial royalties or mineral taxes are payable on freehold coal.
Saskatchewan Crown coal leases are granted under The Crown Minerals Act and The Coal Disposition Regulations, 1988, for terms of 15 years. The leases are renewable for further terms of 15 years each, subject to The Crown Minerals Act and the regulations in force at the time of renewal. In Saskatchewan, Crown royalties in the amount of 15% of the mine-mouth value of coal are payable quarterly pursuant to The Crown Coal Royalty Schedule to The Coal Disposition Regulations, 1988. The Mineral Taxation Act, 1983, levies two taxes against freehold coal rights and production. One is an annual freehold mineral tax of $960 per nominal section. The other is a freehold coal production tax, payable quarterly, of 7% on the mine mouth value of coal.
We believe that we have satisfied all lease conditions in order to retain the properties and keep the leases in place.
Coal - U.S. and Coal - Canada Segment Customers
U.S. Coal Segment
In 2015, our Coal - U.S. Segment derived approximately 75% of its total revenues from coal sales to five power plants: Colstrip Units 3&4 (26%); Limestone Generating Station (16%); American Electric Power Company, Inc. (13%), Colstrip Units 1&2 (11%); and Pacificorp Energy, Inc. (9%). We sell the majority of our tons under contracts with remaining supply obligation terms of three years or more. We provide coal delivery via conveyor belt to our mine-mouth customers, and also sell coal and lignite on a Freight On Board, or FOB, basis to our other customers. The purchaser of coal normally bears the cost of transportation and risk of loss from load-out to its final destination.
Colstrip. The Colstrip Mine has two long-term, cost-plus contracts with the adjacent Colstrip Station power generating facility. The supply agreement for Colstrip Units 1 and 2 has a projected term through 2022 and expected tons of 2.3 million annually. A second agreement for Colstrip Units 3 and 4 provides for approximately 6.3 million tons per year and is set to expire at the end of 2019. The agreement related to Units 3 and 4 also has provisions for specific returns on capital investments.
Absaloka. The Absaloka Mine operates primarily in the open market and has several two- to eleven-year contracts with various parties. The capacity of the mine ranges between 5.5 million and 7.4 million tons annually. In 2013 and 2014, the Absaloka Mine sold 4.2 million and 6.6 million tons, respectively. The low annual sales in 2013 relative to mine capacity was due to an extended outage of the Sherburne County Generating Station in Becker, Minnesota, which is the mine’s largest customer. In 2015, the Absaloka Mine sold 5.8 million tons. Burlington Northern Santa Fe provides rail service to the mine, which also has the ability to load and ship coal via over-the-road trucks. Prices under these agreements are based upon certain actual mine costs and certain inflation indices for such items as diesel fuel. In October 2015, Xcel Energy, the owner of the Sherburne County Generating Station, announced a plan to retire Units 1 and 2 of the plant’s three generating units in 2026 and 2023, respectively.
Savage. The Savage Mine supplies approximately 0.3 million tons annually to the Lewis & Clark Power Station and Sidney Sugars Incorporated. Both customers are located within close proximity to the mine and coal deliveries are provided via over-the-road truck. The mine entered into new agreements with both customers in 2012 that both expire in December 2017. Prices under these agreements are based on certain actual mine costs, commodity indices (for items such as diesel fuel), and the agreements contain provisions for capital recovery.

14


Jewett. The Jewett Mine has a cost-plus agreement with NRG Texas Power’s adjacent Limestone Generating Station. NRG Texas Power is also responsible for the mine’s capital and reclamation expenditures. The agreement has a term through 2018, which may be extended by NRG Texas Power for up to an additional ten years or until the mine’s reserves are exhausted. NRG has the option to determine volumes to be delivered, which average between four and five million tons annually. NRG may terminate the agreement at its discretion.
Beulah. The Beulah Mine supplies approximately 2.5 million tons annually to the adjacent Coyote Electric Generating Plant via conveyor belt under an agreement that expires in May 2016. The Coyote agreement has provisions for specific returns on capital investment. We have received notice that the Coyote Electric Generating Plant will not be renewing its contract past 2016. The Beulah Mine also supplies approximately 0.5 million tons annually via rail to the Heskett Power Station under an agreement that expires in 2021. Prices under these agreements are based upon certain actual mine costs and certain inflation/commodity indices for items such as diesel fuel.
Buckingham. The Buckingham Mine conducts underground room and pillar mining operations in Ohio. Buckingham is strategically located near WMLP’s New Lexington complex, which has access to the Norfolk Southern rail system and a state-of-the-art preparation plant strategically located for efficient rail and river transportation for both Buckingham and WMLP coal. The Buckingham Mine supplies coal to AEP under a five-year coal supply agreement that includes an obligation to purchase a minimum of 5.5 million tons of coal. Buckingham’s proximity to WMLP’s New Lexington complex allows us to substitute tonnage to be supplied by WMLP to AEP when it is economically advantageous to do so.
Coal - Canada Segment Customers
Our Coal - Canada Segment sells the majority of its tons under contracts with remaining supply obligation terms of between one and 40 years. In 2015 our Coal - Canada Segment derived approximately 80% of its total revenues from coal sales to two customers and one country: SaskPower (42%), the country of Japan (22%) and ATCO Power (17%). The majority of our Prairie Operation’s coal production is sold to Canadian utilities for electricity production, and all of our Prairie Operation’s five mines are mine mouth operations. The Coal Valley Mine produces thermal coal which is exported primarily to the Asia-Pacific market via rail and ocean vessel under reserved port capacity.
Paintearth. The Paintearth Mine is a surface mine located in Central Alberta south of the Village of Forestburg. The mine operates two active pits and supplies sub-bituminous coal to the four generating units at the Battle River Generating Station which are owned and operated by Alberta Power (2000) Ltd. (“ATCO Power"). Current annual production of the mine is 1.5 million tons. The coal supply contract for the mine expires in 2022.
Sheerness. The Sheerness Mine is a surface mine located in South Central Alberta south of the Town of Hanna. The mine operates two active pits and supplies sub-bituminous coal to the two generating units at the Sheerness Generating Station which is owned by TransAlta Corporation and ATCO Power and operated by ATCO Power. Current annual production of the mine is 3.6 million tons. The current coal supply contract for the mine expires in 2026.
Poplar River. The Poplar River Mine is a surface mine located in South Central Saskatchewan near the Town of Coronach. The mine operates two active pits and supplies lignite coal to the two generating units at the Poplar River Generating Station which is owned and operated by Saskatchewan Power Corporation (“SaskPower”). Current annual production of the mine is 4.1 million tons. The coal supply contract for the mine expires in 2029. The Poplar River Mine owns and operates the railway from the mine to the generating station.
Estevan. The Estevan Mine combines two of our adjacent mines in southeastern Saskatchewan, the Bienfait Mine and the Boundary Dam Mine, which supply an approximate combined 6.4 million tons per year to SaskPower, domestic consumers and the char and activated carbon plants. Our contract with SaskPower related to the Estevan Mine is through 2024. The Estevan Mine operates four active pits and supplies lignite coal to the Boundary Dam Generating Station (4 Units) (“Boundary Dam”), the Shand Generating Station (1 Unit) (“Shand”), the activated carbon plant, the char plant, as well as some domestic sales. SaskPower has constructed and commissioned a carbon dioxide capture and sequestration (“CCS”) facility at Boundary Dam and a carbon capture test facility at Shand. This combined project is the largest commercial scale CCS facility in the world, and is funded by the government of Saskatchewan with backing from the Canadian government, and, should mitigate the impact of Canadian GHG regulations on Boundary Dam.
Genesee. The Genesee Mine is a surface mine located in central Alberta north of the Town of Warburg and close to Edmonton. The mine operates two active pits and supplies sub-bituminous coal to the three units at the Genesee Generating Station which are owned by Capital Power and TransAlta Corporation and operated by Capital Power. The Genesee Mine, which is a joint venture between Capital Power and Westmoreland, supplies approximately 5.7 million tons per year to Capital Power and the contract runs for the life of the mine.

15


Coal Valley. The Coal Valley Mine is a surface mine located in west central Alberta south of the Town of Edson. The mine operates both truck/shovel and dragline pits and utilizes a dragline for coal removal. The mine exports high quality sub-bituminous coal to customers in the Asia-Pacific market as well as supplying some domestic customers. Current annual clean production of the mine is 2.1 million tons and the plant has capacity to operate at approximately 4.0 million tons per year.

 Activated Carbon Plant. A 50/50 joint venture with Cabot Corporation, the plant was initially commissioned in June 2010. The activated carbon plant is located at the Estevan Mine and the activated carbon produced is sold to coal-fired power producers for the purpose of mercury removal from flue gas emitted to the atmosphere. Regulations regarding mercury emissions have significantly increased demand for this product.
Char Plant. Our char plant produces approximately 107,000 tons of lignite char per year using coal from the Estevan Mine. The char is sold to manufacturers of barbeque briquettes in the United States.
Competition
While the North American coal industry is intensely competitive, we focus on niche coal markets where we take advantage of long-term coal contracts with neighboring power plants. For our open market coal sales, we compete with many other suppliers of coal to provide fuel to power plants. Additionally, coal producers compete with producers of alternative fuels used for electrical power generation, such as nuclear energy, natural gas, hydropower, petroleum and wind. Costs and other factors such as safety, environmental and regulatory considerations relating to these alternative fuels affect the overall demand for coal as a fuel.
Coal - U.S. Segment
We believe that our mines have a competitive advantage based on three factors: 
all of the mines in our Coal - U.S. Segment are the most economic suppliers to each of their respective principal customers, as a result of transportation advantages over our competitors;
nearly all of the power plants we supply were specifically designed to use our coal; and
the plants we supply are among the lowest cost producers of electric power in their respective regions and are among the cleaner producers of power from solid fossil fuels.
Because of the foregoing, we believe that our current customers in our Coal - U.S. Segment are more likely to be dispatched to produce power and to continue purchasing coal extracted from our mines.
The principal customers of the Colstrip, Jewett, and Beulah mines are located adjacent to the mines; we deliver the coal for these customers by conveyor belt instead of more expensive means such as truck or rail. The customers of the Savage Mine are located approximately 20 to 25 miles from the mine allowing us to transport coal economically by truck.
The Absaloka Mine faces a different competitive situation. The Absaloka Mine sells its coal in the rail market to utilities located in the northern tier of the United States served by BNSF. These utilities may purchase coal from us or from other producers. We compete with other producers based on price and quality, with the purchasers also taking into account the cost of transporting the coal to their plants. The Absaloka Mine enjoys an over 300-mile rail advantage over its principal competitors from the Southern Powder River Basin in supplying customers located in the northern tier. Rail rates have increased over the last several years by 50 to 100%, which strengthens our competitive advantage.
Coal - Canada Segment
The principal customers of the Paintearth, Sheerness, Genesee, Poplar River and Estevan Mines have power plants that are located adjacent to the mines and the coal is delivered to these customers economically by truck.  Our proximity gives us a distinct advantage over our competition.
The Coal Valley Mine produces coal for export customers, and has contracts with railway and port entities for delivery. The coal is railed to and sold at a port facility on the coast of British Columbia, Canada.  The export customers are generally Asian power utilities. Our export customers may purchase coal from us or from other producers around the world with similar coal quality, access to ports, and economical shipping to the customer. Some competitors are located closer to the Asian customers' facilities.

16


Coal - WMLP Segment
General
WMLP is a growth-oriented, low-cost producer and marketer of high-value thermal coal to U.S. utilities and industrial users, and is the largest producer of surface mined coal in Ohio. WMLP markets its coal primarily to large electric utilities with coal-fired, base load scrubbed power plants under long-term coal sales contracts. It focuses on acquiring thermal coal reserves that it can efficiently mine with its large-scale equipment. WMLP’s reserves and operations are well positioned to serve its primary market areas of the Midwest, northeastern United States and Rocky Mountain region.
For the year ended December 31, 2015, WMLP sold $7.9 million tons of coal, 87% of which were sold pursuant to long-term coal supply contracts and generated revenue of approximately $294.6 million. As of December 31, 2015, WMLP owned or controlled approximately 145 million tons of coal reserves, of which 24.3 million tons were leased or subleased to others.
Customers
WMLP’s primary customers are electric utility companies that purchase coal under long-term coal sales contracts. Substantially all of its customers purchase coal for terms of one year or longer, but it also supplies coal on a short-term or spot market basis for some of its customers. In 2015, WMLP derived approximately 58% of its total coal revenues from sales to two customers: American Electric Power Company, Inc. (42%) and Pacificorp Energy, Inc. (16%). A portion of these sales were facilitated by coal brokers.
WMLP Properties
As of December 31, 2015, WMLP operated 14 active surface mines and managed these mines as five mining complexes located in eastern Ohio and one mine located in Wyoming. These mining facilities include two preparation plants, both of which receive, wash, blend, process and ship coal produced from its active mines. 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 also owns and operates seven augers, moving them among its mining complexes, as necessary, and two highwall miner systems. In August 2015, we completed the Kemmerer Drop to WMLP. The Kemmerer Mine supplies approximately 2.7 million tons per year to the adjacent Naughton Power Station via conveyor belt under an agreement that expires in December 2021. Kemmerer also supplies approximately 1.7 million tons a year to various industrial customers, including Tata Chemicals North America Inc. and FMC Corporation, through long-term contracts extending to 2026. These industrial customers are supplied via both short haul rail and truck. Prices under supply agreements related to the Kemmerer Mine are based upon certain actual mine costs and certain inflation/commodity indices for items such as diesel fuel.
Currently, 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. The mobile equipment utilized at its mining operations is replaced on an on-going basis with new, more efficient units based on equipment age and mechanical condition.
The following table provides information about the mines held by WMLP as of December 31, 2015. This table does not include any royalty properties as they are discussed below in the “Royalty Revenues” section:

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Coal - WMLP
Cadiz
 
Tusca-rawas
 
Plainfield (4)
 
Belmont
 
New Lexington
 
Noble
 
Muhlen-berg(4)
 
Tusky
(4)
 
Kemmerer
(5)
 
Total
Owned by
Oxford Mining Company, LLC
 
Oxford Mining Company, LLC
 
Oxford Mining Company, LLC
 
Oxford Mining Company, LLC
 
Oxford Mining Company, LLC
 
Oxford Mining Company, LLC
 
Oxford Mining Company -
Kentucky, LLC
 
Oxford Mining Company, LLC
 
Westmoreland Kemmerer, Inc.
 
 
Location
Harrison County, Ohio
 
Tuscara-was County, Ohio
 
Musking-um, Guernsey and Coshocton Counties, Ohio
 
Belmont County, Ohio
 
Perry, Athens and Morgan Counties, Ohio
 
Noble and Guernsey Counties, Ohio
 
Muhlen-berg and McLean Counties, Kentucky
 
Harrison and Tuscara-was Counties, Ohio
 
Lincoln County, WY
 
 
Coal reserves
(thousands of tons)
Proven
6,275

 
5,330

 
3,622

 
9,205

 
3,379

 
229

 
1,227

 
18,965

 
80,556

 
128,788

Probable
931

 

 

 
531

 
173

 

 
568

 
5,366

 
8,867

 
16,436

Total proven and probable reserves (thousands of tons)
7,206

 
5,330

 
3,622

 
9,736

 
3,552

 
229

 
1,795

 
24,331

 
89,423

 
145,224

Permitted reserves
(thousands of tons)
5,466

 
1,946

 
282

 
1,327

 
1,022

 

 
1,227

 
16,720

 
30,906

 
58,896

2015 production
(thousands of tons)
2,125

 
673

 

 
644

 
551

 
17

 

 

 
4,471

 
8,481

Estimated life of permitted reserves (1)
2018

 
2018

 
2017

 
2016

 
2017

 
2015

 
2020+

 
2025+

 
End 2024

 
 
 Lessor
Private parties
 
Private parties
 
Private parties
 
Private parties
 
AEP, Private parties
 
Private parties
 
Private parties
 
Private parties
 
Private parties, Fed Gov.
 
 
Lease term
Varies
 
Varies
 
Varies
 
Varies
 
Varies
 
Varies
 
Varies
 
Varies
 
Varies
 
 
Current production capacity
(thousands of tons)
2,580

 
600

 

 
660

 
600

 

 

 

 
7,000

 
 
Coal type
Bituminous
 
Bituminous
 
Bituminous
 
Bituminous
 
Bituminous
 
Bituminous
 
Bituminous
 
Bituminous
 
Sub-bituminous
 
 
Major customers
American Electric Power Company, Inc.; and East Kentucky Power Cooperative
 
American Electric Power Company, Inc.; and East Kentucky Power Cooperative
 
American Electric Power Company, Inc.; and East Kentucky Power Cooperative
 
American Electric Power Company, Inc.; and East Kentucky Power Cooperative
 
American Electric Power Company, Inc.; and East Kentucky Power Cooperative
 
American Electric Power Company, Inc.; and East Kentucky Power Cooperative
 
N/A - See Note (4)
 
N/A - See Note (4)
 
PacifiCorp, various industrial customers
 
 
Delivery method
Barge, rail, truck
 
Truck
 
Truck
 
Barge, truck
 
Rail, truck
 
Barge, truck
 
N/A - See Note (4)
 
N/A - See Note (4)
 
Conveyor, rail, truck
 
 
Approx. heat content
(BTU/lb.) (2)
11,431

 
11,760

 
11,711

 
11,779

 
11,551

 
11,286

 
11,424

 
12,900

 
9,919

 
 
Approx. sulfur content (%) (3)
2.7

 
3.9

 
4.4

 
4.4

 
4.5

 
5.3

 
3.5

 
2.1

 
0.78

 
 
Year current complex opened
2000

 
2003

 
1990

 
1999

 
1993

 
2006

 
2009

 
2003

 
1950

 
 
Total tons mined since inception (thousands of tons)
450,828

 
192,534

 
107,489

 
15,838

 
174,678

 
191,730

 
107,489

 
15,148

 
188,737

 
 
 ____________________
(1)
Approximate year in which permitted reserves would be exhausted, based on current mine plan and production rates.

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(2)
Approximate heat content applies to the coal mined in 2015.
(3)
Approximate sulfur content applies to the tons mined in 2015.
(4)
Mining complex was inactive during 2015.
(5)
The Elkol Underground Mine opened in 1950 and the Sorenson Surface Operations opened in 1963. Tons mined since inception for the Kemmerer Mine are for tons mined from 1950 through 2015.

Royalty Revenues

Tusky Coal Reserves

WMLP 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, WMLP sold the Tusky mining complex, and subleased the associated underground coal reserves to the purchaser in exchange for a royalty. There are seven years remaining on WMLP's 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 WMLP assign its interest to the sublessee for defined and predetermined consideration. For the year ended December 31, 2015, WMLP 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, WMLP completed the sale of certain oil and gas rights on land in eastern Ohio for $0.2 million, $6.1 million and $6.3 million, respectively, plus future royalties. There were no oil and gas rights sales in 2015. For the fiscal year ended December 31, 2015, WMLP generated $0.9 million in royalty revenue from the receipt of these oil and gas royalties.

Limestone Revenues

At WMLP’s Daron and Strasburg mines, limestone is removed in order to access the underlying coal. WMLP sells this limestone to a third party that crushes the limestone before selling it to local governmental authorities, construction companies and individuals. The third party pays WMLP for this limestone based on a percentage of the revenue it receives from the limestone sales. For the year ended December 31, 2015, WMLP produced and sold 0.7 million tons of limestone, and its revenues included $2.9 million in limestone sales.

Competition
The markets in which WMLP sells its coal are highly competitive. It competes directly with other coal producers and indirectly with producers of other energy products that provide an alternative to coal. While WMLP does not compete with producers of metallurgical coal or lignite, it does have limited competition from producers of Powder River Basin coal (sub-bituminous coal) in its 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., CONSOL, Foresight Energy, Hallador Energy Company, Peabody Energy Corp., Rhino Resource Partners, L.P. and various other smaller, independent producers.
Seasonality
Our coal business has historically experienced only limited variability in its results due to the effect of seasons; however, we are impacted by seasonality due to weather patterns and our customer's annual maintenance outages which typically occur during the second quarter. In addition, our customers generally respond to seasonal variations in electricity demand based upon the number of heating degree days and cooling degree days. Due to stockpile management by our customers, our coal sales may not experience the same direct seasonal volatility; however, extended mild weather patterns can impact the demand for our coal. Our sales typically benefit from decreases in customers' stockpiles due to high electricity demand. Conversely, when these stockpiles increase, demand for our coal will typically soften. Further, our ability to deliver coal is impacted by the seasons. Because the majority of our mines are mine-mouth operations that deliver their coal production to adjacent power plants, our exposure to transportation delays or outages as a result of adverse weather conditions is limited.

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Material Effects of Regulation
We are subject to extensive regulation with respect to environmental and other matters by federal, state, provincial and local authorities in both the United States and Canada. Federal laws in the U.S. to which we are subject include the Surface Mining Control and Reclamation Act of 1977, or SMCRA, the Clean Air Act, the Clean Water Act, the Toxic Substances Control Act, the Endangered Species Act, the Migratory Bird Treaty Act, the Comprehensive Environmental Response, Compensation and Liability Act, the Emergency Planning and Community Right to Know Act and the Resource Conservation and Recovery Act. The United States Environmental Protection Agency, or EPA, and/or other authorized federal or state agencies administer and enforce these laws. We are also subject to extensive regulation regarding safety and health matters pursuant to the United States Mine Safety and Health Act of 1977, which is enforced by the U.S. Mine Safety and Health Administration ("MSHA"). Provincial laws in Alberta to which we are subject include, among others, the Responsible Energy Development Act, the Mines and Minerals Act, the Coal Conservation Act, the Environmental Protection and Enhancement Act, the Public Lands Act, and the Water Act as well as related regulations, directives, policies and guidelines. Provincial laws in Saskatchewan to which we are subject include, among others, The Crown Minerals Act, The Ecological Reserves Act, The Environmental Assessment Act, The Environmental Management and Protection Act, 2002, The Provincial Lands Act, and the Wildlife Act, 1998, as well as related regulations, directives, policies and guidelines. The federal laws in Canada to which we are subject include, among others, the Fisheries Act, the Canadian Environmental Assessment Act, 2012, the Canadian Environmental Protection Act, 1999, the Species at Risk Act, the Migratory Birds Convention Act as well as related regulations, directives, policies and guidelines, and various provincial and federal climate change laws and initiatives. Non-compliance with federal, tribal and state and provincial 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.

Following passage of The Mine Improvement and New Emergency Response Act of 2006, amending the Federal Mine Safety and Health Act of 1977, MSHA significantly increased the oversight, inspection and enforcement of safety and health standards and imposed safety and health standards on all aspects of mining operations. There has also been a dramatic increase in the dollar penalties assessed by MSHA for citations issued over the past two years. 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 Coal Company. 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. Our Jewett mine won the Sentinels of Safety Award for 2014 which is the United State's most prestigious award given for recognition of mining safely due to the mine having no reportable incidents last year.
Safety performance in 2015 at our mines was as follows:

2015
 
Reportable
Rate
 
Lost Time
Rate
U.S. Operations (excluding WMLP mines)
2.76

 
0.72

WMLP Operations
1.05

 
0.35

Canadian Operations
3.99

 
0.64

U.S. National Average
1.82

 
1.28

U.S. Regulation
The following provides brief summaries of certain U.S. federal laws and regulations to which we are subject and their effects upon us:
Surface Mining Control and Reclamation Act. SMCRA establishes minimum national operational, reclamation and closure standards for all surface coal mines. SMCRA requires that comprehensive environmental protection and reclamation standards be met during the course of and following completion of coal mining activities. Permits for all coal mining operations must be obtained from the Federal Office of Surface Mining Reclamation and Enforcement ("OSM"), or, where state regulatory agencies have adopted federally approved state programs under SMCRA, the appropriate state regulatory authority. States that operate federally approved state programs may impose standards that are more stringent than the requirements of SMCRA and OSM’s regulations and, in many instances, have done so. Permitting under SMCRA has generally become more difficult in

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recent years, which adversely affects the cost and availability of coal purchased by ROVA, especially in light of significant permitting issues affecting the Central Appalachia region. This difficulty in permitting also affects the availability of coal reserves at our coal mines. It is our policy to comply in all material respects with the requirements of the SMCRA and the state and tribal laws and regulations governing mine reclamation.
Clean Air Act and Related Regulations. The U.S. Clean Air Act ("CAA"), and comparable state laws that regulate air emissions affect coal mining operations both directly and indirectly. Direct impacts on coal mining and processing operations include Clean Air Act permitting requirements and emission control requirements relating to air pollutants, including particulate matter, which may include controlling fugitive dust. The Clean Air Act indirectly affects coal mining operations by extensively regulating the emissions of particulate matter, sulfur dioxide, nitrogen oxides, mercury and other compounds emitted by coal-fired power plants. It also affects us directly because ROVA is subject to significant regulation under the Clean Air Act. In recent years, Congress has considered legislation that would require increased reductions in emissions of sulfur dioxide, nitrogen oxide and mercury, as well as GHGs. The air emissions programs, regulatory initiatives and standards that may affect our operations, directly or indirectly, include, but are not limited to, the following:
Greenhouse Gas Emissions Standards. In August of 2015, EPA finalized standards for greenhouse gases for new and modified electric generating units (EGUs) referred to as “new source performance standards” or NSPS. The final NSPS for coal-fired EGUs is set at 1,400 pounds of CO2 / megawatt hour on an average annual basis which would, with few possible exceptions, require the installation of partial carbon capture and sequestration at new or modified coal-fired EGUs. Under the CAA, new source performance standards like the GHG NSPS have binding effect from the date of the proposal, which in this case was January 8, 2014. Therefore, any new coal-fired EGU must comply with this standard, which is likely to be major obstacle to the construction and development of any new coal-fired generation capacity. Existing coal-fired generation, however, is also now subject to GHG performance standards that the EPA asserts will reduce GHG emissions from the power sector by 32% from 2005 levels by 2030. At the same time the EPA issued the GHG NSPS, EPA finalized existing source standards for fossil-fuel fired power plants, which EPA refers to as the Clean Power Plan. The final Clean Power Plan imposes stringent standards on existing fossil-fuel fired EGUs that reflect EPA’s assessment of the “best system of emission reduction,” (BSER) including (1) average heat rate improvements of 6% for coal-fired power plants; (2) the re-dispatch of power based on an assumption that underutilized capacity at natural gas combined cycle facilities can be increased to an average of 75% of net summer capacity; and (3) the substitution of coal generation with renewable energy. These existing source standards are implemented by the states, which must meet individual GHG emission “goals” beginning in 2022 with phased reductions through 2030. Each state can choose either a rate-based or a mass-based goal that reflects the mix of natural gas and coal-fired generation in the state. The final goals have a greater impact on states with substantial coal-fired generation; Wyoming and North Dakota, for example, are faced with greater than 40% emission reductions from a 2012 baseline. The states have until September of 2016 to submit plans to EPA to implement and enforce the state-specific BSER, although two-year extensions be requested by states in an initial submittal. States and industry groups challenged the rule in the U.S. Court of Appeals for the D.C. Circuit and requested a stay pending judicial review. Although the D.C. Circuit denied the stay request, in February of 2016, the U.S. Supreme Court issued a stay of the Clean Power Plan pending judicial review of the rule, including potential review by the Supreme Court. The D.C. Circuit is reviewing the rule under an expedited briefing schedule, with oral arguments to be held in June of 2016. A number of states, including Montana and Utah, have ceased development of implementation plans, while others, including Colorado, are continuing to work on plan development. If upheld by the courts, these rules have the potential to adversely affect our revenues and profitability, although it is difficult at this stage to determine the timing and extent of any such effects, or to determine the requirements of state plans resulting from these proposals that may ultimately be promulgated and require implementation. In June 2014, the U.S. Supreme Court in UARG v. EPA struck down the EPA’s GHG permitting rules to the extent they imposed on sources a requirement to obtain an air emissions permit and comply with emissions limits solely as a result of GHG emissions. The Court upheld the EPA’s authority to impose the Best Available Control Technology (“BACT”) on large industrial sources such as power plants that are otherwise required to obtain an air emissions permit under the Prevention of Significant Deterioration program or the Title V program of the Clean Air Act. In April 2015, the U.S. Court of Appeals for the D.C. Circuit rejected motions filed by industry groups and certain states arguing that GHG permitting rules should be vacated in their entirety while EPA undertakes a new rulemaking determining how to address the Supreme Court’s ruling. Therefore the regulatory provisions addressing GHG emissions from large industrial sources, such as fossil-fuel fired EGUs, remain in place. EPA has not yet initiated a rulemaking to address the Supreme Court’s decision.
Mercury Air Standards. In February 2012, the EPA published national emission standards under Section 112 of the CAA setting limits on hazardous air pollutant emissions from coal- and oil-fired EGUs, often referred to as the “Mercury Air Toxics Standards,” or “MATS Rule.” While the MATS Rule will generally require all coal- and oil-

21


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 EPA to conduct a cost assessment but without vacatur, allowing the rule to remain in effect while EPA conducts the rulemaking. On December 1, 2015, 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. EPA indicated that it expects to issue a final finding by April 15, 2016.
National Ambient Air Quality Standards (“NAAQS”) for Criteria Pollutants. The CAA requires the EPA to set standards, referred to as NAAQS, for six common air pollutants, including nitrogen oxide and sulfur dioxide. Areas that are not in compliance (referred to as non-attainment areas) with these standards must take steps to reduce emissions levels. Meeting these limits may require reductions of nitrogen oxide and sulfur dioxide emissions. Although our operations are not currently located in non-attainment areas, we could be required to incur significant costs to install additional emissions control equipment, or otherwise change our operations and future development if that were to change. On June 22, 2010, the EPA published a final rule that tightens the NAAQS for sulfur dioxide. On February 17, 2012, the EPA published final NAAQS for nitrogen dioxide. On January 15, 2013, the EPA published final NAAQS for particulate matter; the EPA lowered the annual standard for particles less than 2.5 micrometers in diameter but maintained the NAAQS for particles less than 10 micrometers in diameter. EPA finalized designations for the sulfur dioxide NAAQS in 2013 for a handful of counties and delayed designations for the remainder of the country. EPA has proposed guidance that would allow states to use both monitoring and modeling for the remaining designations, but has not finalized the guidance or set any deadlines for state recommendations. EPA finalized nonattainment designations for nitrogen dioxide in January 2012. We do not know whether or to what extent these developments might affect our operations or our customers’ businesses. In 2008, the EPA finalized the current 8-hour ozone standard. In October 2015, the EPA issued a final rule lowering the ozone standard further. While it is likely that these and any future developments resulting in stricter NAAQS will to some degree adversely affect us, it is difficult at this stage to determine the timing and extent of such effects.
Clean Air Interstate Rule and Cross-State Air Pollution Rule (“CAIR”) and Cross-State Air Pollution Rule (“CSAPR”). The CAIR calls for power plants in 28 states and the District of Columbia to reduce emission levels of sulfur dioxide and nitrogen oxide pursuant to a cap-and-trade program similar to the system now in effect for acid rain. In 2008, the U.S. Court of Appeals for the District of Columbia Circuit found that the CAIR was fatally flawed, but ultimately agreed to allow it to remain in place pending the EPA’s development of a replacement rule because of concerns about potential disruptions. In June 2011, the EPA finalized the CSAPR as a replacement rule to the CAIR, which requires 28 states in the Midwest and eastern seaboard of the United States to reduce power plant emissions that cross state lines and contribute to ozone and/or fine particle pollution in other states. Under the CSAPR, the first phase of the nitrogen oxide and sulfur dioxide emissions reductions would commence in 2012 with further reduction effective in 2014. On December 15, 2011, the EPA finalized a supplemental rule making to require Iowa, Michigan, Missouri, Oklahoma and Wisconsin to make summertime reductions to nitrogen oxide emissions under the CSAPR ozone-season control program. However, on December 30, 2011, the U.S. Court of Appeals for the District of Columbia Circuit stayed the implementation of CSAPR pending resolution of judicial challenges to the rules and ordered the EPA to continue enforcing the CAIR until the pending legal challenges have been resolved. In August 2012, the U.S. Court of Appeals vacated the CSAPR in a 2-to-1 decision and left the CAIR standards in place. In April 2014, the U.S. Supreme Court reversed the D.C. Circuit decision that vacated the CSAPR and remanded the cases for further proceedings consistent with the Court’s opinion, which acknowledged the possibility that under certain circumstances some states may have a basis to bring a particularized, as-applied challenge to the rule. The EPA filed a motion with the D.C. Circuit to lift its stay of the CSAPR and to toll for three years all deadlines that had not already passed as of the date the stay was granted. The D.C. Circuit granted the EPA’s motion in October 2014, and scheduled oral argument on the remaining challenge to the CSAPR for March 2015. In November, 2014 the EPA issued a ministerial rule aligning the CSAPR implementation dates with the Court’s order, with phase 1 reductions beginning in January 2015, and more stringent phase 2 reductions in January 2017. In July 2015, the D.C. Circuit remanded to EPA portions of the 2014 sulfur dioxide and ozone budgets on grounds the reductions were greater than necessary to reduce impacts on downwind states, but did not vacate any portion of the rule. The EPA has indicated that it will address these issues in future rulemakings, but that phase 1 reductions will begin in January 2015, with more stringent phase 2 reductions in January 2017 as necessary.

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Other Programs. A number of other air-related programs may affect the demand for coal and, in some instances, coal mining directly. For example, the EPA has initiated a regional haze program designed to protect and improve visibility at and around national parks, national wilderness areas and international parks. The EPA’s new source review program under certain circumstances requires existing coal-fired power plants, when modifications to those plants significantly change emissions, to install the more stringent air emissions control equipment required of new plants, and concerns about potential failures to comply have resulted in a number of high-profile enforcement actions and settlements over the years resulting in some instances in settlements under which operators install expensive new emissions control equipment. The Acid Rain program under Title IV of the CAA continues to impose limits on overall sulphur dioxide and nitrogen oxide emissions from regulated EGUs. In June 2013, President Obama issued a Climate Action Plan, which included a focus on methane reductions from coal mines. In January 2015, the Administration issued its methane strategy, but it did not include requirements for coal mines. In 2014 the D.C. Circuit upheld 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 Coal Company. Our mines do not produce “compliance coal” for purposes of the Clean Air Act. Compliance coal is coal containing 1.2 pounds or less of sulfur dioxide per million British thermal unit, or Btu. This restricts our ability to sell coal to power plants that do not utilize sulfur dioxide emission controls and otherwise leads to a price discount based, in part, on the market price for sulfur dioxide emission allowances under the Clean Air Act. 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. We are at particular risk of changes in applicable environmental laws with respect to the Jewett Mine, whose customer, the NRG Texas Power- Limestone Station, blends our lignite with compliance coal from Wyoming. Tightened nitrogen oxide and new mercury emission standards could result in an increased blend of the Wyoming coal to reduce emissions. Further, increased market prices for sulfur dioxide emissions and increased coal ash costs could also favor an increased blend of the lower ash Wyoming compliance coal. In such a case, NRG Texas Power has the option to increase its purchases of other coal, reduce purchases of our coal, or to terminate our contract. If NRG terminates the contact, sales of lignite would end and the Jewett Mine would commence final reclamation activities. NRG would pay for all reclamation work plus a margin.
Clean Water Act. The Clean Water Act ("CWA") and corresponding state and local laws and regulations affect coal mining and power generation operations by restricting the discharge of pollutants, including dredged or fill materials, into waters of the U.S. The CWA provisions and associated state and federal regulations are complex and subject to amendments, legal challenges and changes in implementation. In May 2015, the EPA and the U.S. Army Corps of Engineers jointly issued a final rule to clarify which waters and wetlands are subject to regulation under the CWA. The implementation of this rule was stayed nationwide in October 2015. Recent court decisions, regulatory actions and proposed legislation have created uncertainty over CWA jurisdiction and permitting requirements that could either increase or decrease the cost and time spent on CWA compliance.
Endangered Species Act. The Federal Endangered Species Act ("ESA"), and similar state laws protect species threatened with extinction. Protection of endangered and threatened species may cause us to modify mining plans or develop and implement species-specific protection and enhancement plans to avoid or minimize impacts to endangered species or their habitats. A number of species indigenous to the areas where we operate are protected under the ESA. Based on the species that have been identified and the current application of applicable laws and regulations, we do not believe that there are any species protected under the ESA or state laws that would materially and adversely affect our ability to mine coal from our properties.
Resource Conservation and Recovery Act. We may generate wastes, including “solid” wastes and “hazardous” wastes that are subject to the federal Resource Conservation and Recovery Act ("RCRA"), and comparable state statutes, although certain mining and mineral beneficiation wastes and certain wastes derived from the combustion of coal currently are exempt from regulation as hazardous wastes under RCRA. The EPA has limited the disposal options for certain wastes that are designated as hazardous wastes under RCRA. Furthermore, it is possible that certain wastes generated by our operations that currently are exempt from regulation as hazardous wastes may in the future be designated as hazardous wastes, and therefore be subject to more rigorous and costly management, disposal and clean-up requirements.
The EPA determined that coal combustion residuals (“CCR”) do not warrant regulation as hazardous wastes under RCRA in May 2000. Most state hazardous waste laws do not regulate CCR as hazardous wastes. The EPA also concluded that beneficial uses of CCR, other than for mine filling, pose no significant risk and no additional national regulations of such beneficial uses are needed. However, the EPA determined that national non-hazardous waste regulations under RCRA are warranted for certain wastes generated from coal combustion, such as coal ash, when the wastes are disposed of in surface impoundments or landfills or used as minefill. EPA Administrator Gina McCarthy signed the final rule relating to the disposal

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of CCR from electric utilities on December 19, 2014 and submitted it to the Federal Register for publication. The final rule regulates CCR as solid waste under RCRA. The final rule establishes national minimum criteria for existing and new CCR landfills, surface impoundments and lateral expansions. The criteria include location restrictions, design and operating criteria, groundwater monitoring and corrective action, closure requirements and post-closure care and recordkeeping, notification and internet posting requirements. The rule is largely silent on the reuse of coal ash. These changes in the management of CCR could increase both our and our customers’ operating costs and potentially reduce their ability to purchase coal. In addition, contamination caused by the past disposal of CCR, including coal ash, could lead to citizen suit enforcement against our customers under RCRA or other federal or state laws and potentially reduce the demand for coal.
Comprehensive Environmental Response, Compensation, and Liability Act. Under the Comprehensive Environmental Response, Compensation, and Liability Act, also known as CERCLA or Superfund, and similar state laws, responsibility for the entire cost of cleanup of a contaminated site, as well as natural resource damages, can be imposed upon current or former site owners or operators, or upon any party who released one or more designated “hazardous substances” at the site, regardless of the lawfulness of the original activities that led to the contamination. CERCLA also authorizes the EPA and, in some cases, third parties to take actions in response to threats to public health or the environment and to seek to recover from the potentially responsible parties the costs of such action. In the course of our operations, we may have generated and may generate wastes that fall within CERCLA’s definition of hazardous substances. We may also be an owner or operator of facilities at which hazardous substances have been released by previous owners or operators. We may be responsible under CERCLA for all or part of the costs of cleaning up facilities at which such substances have been released and for natural resource damages. We have not, to our knowledge, been identified as a potentially responsible party under CERCLA, nor are we aware of any prior owners or operators of our properties that have been so identified with respect to their ownership or 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 EPA’s GHG permitting rules to the extent they required permits based solely on emissions of GHG. Large sources of air pollutants could still be required to install GHG emission reduction technology. Underground coal mines remain subject to EPA’s GHG Reporting Program, which required mines to submit annual GHG emission estimates to EPA, but that program has not been extended to surface coal mines.
The impact of GHG-related legislation and regulations, including a “cap and trade” structure, on us will depend on a number of factors, including whether GHG sources in multiple sectors of the economy are regulated, the overall GHG emissions cap level, the degree to which GHG offsets are allowed, the allocation of emission allowances to specific sources and the indirect impact of carbon regulation on coal prices. We may not recover from our customers the costs related to compliance with regulatory requirements imposed on us due to limitations in our agreements.
Passage of additional state or federal laws or regulations regarding GHG emissions or other actions to limit carbon dioxide emissions could result in fuel switching from coal to other fuel sources by electricity generators and thereby reduce demand for our coal or indirectly the prices we receive in general. In addition, political and regulatory uncertainty over future emissions controls have been cited as major factors in decisions by power companies to postpone new coal-fired power plants. If these or similar measures, such as controls on methane emissions from coal mines, are ultimately imposed by federal or state governments or pursuant to international treaties, our operating costs or our revenues may be materially and adversely affected. In addition, alternative sources of power, including wind, solar, nuclear and natural gas could become more attractive than coal in order to reduce carbon emissions, which could result in a reduction in the demand for coal and, therefore, our revenues. Similarly, some of our customers, in particular smaller, older power plants, could be at risk of significant reduction in coal burn or closure as a result of imposed carbon costs. The imposition of a carbon tax or similar regulation could, in certain situations,

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lead to the shutdown of coal-fired power plants, which would materially and adversely affect our coal and power plant revenues.
Bonding Requirements. Federal and state laws require mine operators to assure, usually through the use of surety bonds, payment of certain long-term obligations, including the costs of mine closure and the costs of reclaiming the mined land. The costs of these bonds have fluctuated in recent years, and the market terms of surety bonds have generally become more favorable to us. Surety providers are requiring smaller percentages of collateral to secure a bond, which will require us to provide less cash to collateralize bonds to allow us to continue mining. These changes in the terms of the bonds have been accompanied, at times, by an increase in the number of companies willing to issue surety bonds. As of December 31, 2015, we had posted an aggregate of $487.3 million in surety bonds for reclamation purposes, with approximately $102.9 million of cash collateral.
Regulation applicable to ROVA. With respect to our Power segment, ROVA is among the newer and cleaner coal-fired power plants in the United States. Under Title IV of the Clean Air Act, ROVA is exempt from, but may opt-in to receive allocations of sulfur dioxide emission allowances. The plants are among the lowest coal-fired emitters of mercury in the country. Emissions tests performed in 2015 have been submitted to the EPA and have demonstrated that both ROVA units 1 and 2 are compliant with the MATS Rule which must be demonstrated every year. Currently, ROVA is a consumer of sulfur dioxide allowances and nitrogen oxide allowances, and we expect an increase in costs associated with nitrogen oxide allowances at ROVA. With regard to coal ash regulations, ROVA landfills its combustion waste. The landfills are lined and we believe they meet North Carolina Department of Solid Waste regulations. However, on December 19, 2014, the EPA Administrator executed a final rule relating to the disposal of CCR for electric utilities. The rule regulates CCR as a solid waste under RCRA and 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. At this time we are unable to predict the impact that any new regulations might have on our operations.
An important factor relating to the impact of GHG-related legislation and regulations and any other environmental regulations on our Power segment will be our ability to recover the costs incurred to comply with any regulatory requirements that the government ultimately imposes. We may not be able to recover the costs related to compliance with regulatory requirements imposed on us due to limitations in our power purchase agreements. If we are unable to recover such costs incurred by ROVA through allowances or other methods, it could have a material adverse effect on our results of operations at ROVA.
Canadian Regulation
The following is intended as a general overview of certain provincial laws and regulations in Alberta and the federal laws applicable therein to which we are subject and their potential effects upon us. We note that the consequences and penalties arising from the application of any of the below listed enactments are varied and fact specific. Accordingly, the summary that follows should not be considered a comprehensive or conclusive assessment of the possible outcomes of a contravention of the legislation discussed below:
Responsible Energy Development Act. The Responsible Energy Development Act (the “REDA”) establishes the Alberta Energy Regulator (the “AER” or the “Regulator”) and sets out its mandate, structure, powers, duties and functions. The AER administers, among others, the following statutes and accompanying regulations in relation to coal mining and related activities in Alberta: the Mines and Minerals Act, the Coal Conservation Act, the Environmental Protection and Enhancement Act, the Public Lands Act, and the Water Act. The REDA empowers the AER to carry out compliance and enforcement functions under the various pieces of legislation it administers as well as grants it the power to order the payment of administrative penalties.
Mines and Minerals Act. The Mines and Minerals Act (the “MM Act”), and its underlying regulations, governs the management and disposition of rights in Crown owned mines and minerals. The AER recently assumed jurisdiction over issuing exploration authorizations under the MM Act, which any person conducting mining exploration in Alberta is required to obtain in advance of carrying out an exploration program. Exploration programs under the MM Act are subject to investigations and inspections and a contravention of an exploration authorization or of the provisions of the MM Act may result in cancellation of that exploration authorization and/or financial penalties.
Coal Conservation Act. The Coal Conservation Act (the “CC Act”), and its underlying rules, applies to every mine, coal processing plant and in situ coal scheme in the Province of Alberta, and to all coal produced and transported in Alberta. The CC Act imposes permitting, licensing and approval requirements on operators of coal mines and coal processing plants. The CC Act imposes certain environmental conservation requirements on mine operators in relation to, among other things, pollution control, surface abandonment, and prevention of waste. Similar to the US bonding requirements mentioned above, the

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Regulator may require that we deposit financial security to ensure payment of costs associated with suspension of our operations and/or reclamation. Lastly, under the CC Act the Regulator can conduct an inquiry into any matter connected with our Alberta mining operations, the findings of which may result in prosecution for an offense, financial penalties, or injunctions in relation to our operations.
Environmental Protection and Enhancement Act. Under the Environmental Protection and Enhancement Act (the “EPEA”), and its underlying regulations, the AER is responsible for administering environmental impact assessments, and issuing approvals and other authorizations in respect of certain aspects of coal mining operations in Alberta that have the potential to impact the environment. The specific terms and conditions of an EPEA approval may govern emission and effluent limits, monitoring and reporting requirements, research needs, siting and operating criteria, and decommissioning and reclamation requirements. The AER also administers and enforces provisions under the EPEA that concern spills and releases, contaminated sites, land surface reclamation, and hazardous wastes. The Mine Financial Security Program under the EPEA requires us to have sufficient financial resources for carrying out suspension, abandonment, remediation, and surface reclamation work to the standards established by the province and to maintain care and custody of the land until a reclamation certificate has been issued. The Regulator may exercise broad enforcement powers under the EPEA, including conducting compliance checks, inspections and investigations, issuing enforcement orders, taking enforcement actions, issuing clean-up orders, suspending and/or canceling operating authorizations, demanding cost recovery or charging us for an offense under the EPEA; all of which may have a material adverse effect on our business, depending on the specific circumstances surrounding the enforcement action taken by the Regulator.
Public Lands Act. Under the Public Lands Act, the AER carries out its responsibility of ensuring that energy exploration, development, and ongoing operations on public land, including coal mining, are carried out in a responsible manner and in accordance with applicable legislation. The AER amends, maintains, and inspects all land-use dispositions and authorizations for energy activities. The AER also administers the enforcement and compliance provisions of the Public Lands Act, which empower it to cancel, suspend or amend a disposition where its terms and conditions or the provisions of the legislation have been contravened and to issue financial penalties in respect of offences under the Public Lands Act. Similar to contraventions of other pieces of legislation discussed in this section, an enforcement action or a penalty has the potential to constitute a material adverse effect on our operations.
Water Act. The Water Act, and its underlying regulations, requires that authorizations be obtained prior to undertaking construction activities around, and prior to diverting water from, a water body. Under the Water Act, a corporation conducting an activity without the requisite approval or in contravention of the specific terms and conditions of an authorization is liable to a fine and/or administrative penalty, which may have a material adverse effect on our business.
The Crown Minerals Act. Similar to the MM Act in Alberta, the Crown Minerals Act (the “CM Act”), and its underlying regulations, governs the management and disposition of rights in Crown owned mines and minerals. The Saskatchewan Ministry of Economy administers the CM Act and the issuance of dispositions authorizing the exploration and development of coal resources in the province. Contravention of the terms of a Crown disposition or the provisions of the CM Act may result in cancellation of that disposition and/or financial penalties, both of which may have a material adverse effect on our business.
The Ecological Reserves Act. The Ecological Reserves Act (the “ER Act”) protects unique, natural ecosystems and landscape features in Saskatchewan through the designation of Crown land as ecological reserves. Under the ER Act, the Lieutenant Governor in Council may make regulations and orders designating any Crown land as an ecological reserve, enlarging any ecological reserve, and restricting the activities which may be carried out on an existing ecological reserve. Designation of either of our Saskatchewan mine properties as an ecological reserve may restrict our mining activities on those properties, or cause us to modify mining plans; however, we do not have any reason to believe that either of our Saskatchewan properties are at risk of being designated an ecological reserve at this time.
 
The Environmental Assessment Act. The Environmental Assessment Act (the “EA Act”) provides a means to ensure that development proceeds with adequate environmental safeguards and in a manner broadly understood by and acceptable to the public through the integrated assessment of environmental impact. Under the EA Act, the Saskatchewan Ministry of Environment is responsible for administering environmental assessments, and issuing approvals and other authorizations in respect of certain aspects of coal mining operations in Saskatchewan that have the potential to impact the environment. Similar to the AER’s powers in relation to environmental impact assessments issued under the EPEA, the Ministry of Environment may issue an EA Act approval on any terms and conditions considered necessary or advisable to protect the environment. The Ministry of Environment has broad enforcement powers under the EA Act, including enjoining a development contrary to the EA Act or the terms and conditions of any ministerial approval, conducting investigations, and issuing financial penalties for offenses under the EA Act; all of which may have a material adverse effect on our business, depending on the specific circumstances surrounding the enforcement action taken by the Ministry of Environment.

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The Environmental Management and Protection Act, 2002. The Environmental Management and Protection Act, 2002 (the “EMP Act”), and its underlying regulations, protects the air, land and water resources of Saskatchewan through regulating and controlling potentially harmful activities and substances. The Saskatchewan Ministry of Environment administers and enforces provisions under the EMP Act that concern unauthorized discharges of substances into the environment, contaminated sites, surface land reclamation, hazardous waste, water quality, and activities around water bodies. The Saskatchewan Ministry of Environment may exercise broad enforcement powers under the EMP Act, including conducting compliance checks, inspections and investigations, issuing environmental protection orders, suspending or canceling operating authorizations, demanding cost recovery or charging us for an offence under the EMP Act; all of which may have a material effect on our business, depending on the specific circumstances surrounding the enforcement action taken by the Ministry of Environment.
The Provincial Lands Act. The Provincial Lands Act (the “PL Act”) creates authority for the Saskatchewan Ministry of Environment to carry out its responsibilities in relation to the management, transfer, sale, lease or other disposition of Crown lands, including lands used for coal mining. The Ministry of Environment also administers the enforcement and compliance provisions of the PL Act, which may include cancellation of a disposition where its terms and conditions or the provisions of the legislation have been contravened and to issue financial penalties in respect of offenses under the PL Act. Similar to contraventions of other legislation discussed in this section, an enforcement action or a penalty has the potential to constitute a material adverse effect on our operations.
The Wildlife Act, 1998. The Wildlife Act, 1998 (the “Wildlife Act”) provides for the management, conservation and protection of wildlife resources through the issuance and revocation of licenses, the prosecution of wildlife offenses and the establishment of annual hunting seasons. The Wildlife Act includes provisions to designate and protect species at risk in Saskatchewan, of which there are currently 15 at-risk plants and animals identified in the Wildlife Act. Identification of a species at risk may cause us to modify mining plans or develop and implement protection plans to avoid or minimize impacts to species protected under the Wildlife Act; however, we do not believe that there are any species protected under the Wildlife Act that would materially and adversely affect our ability to mine coal from our Saskatchewan properties.
Fisheries Act. The Fisheries Act, and its underlying regulations, contains two key provisions on conservation and protection of fish habitat that have the potential to have a material effect on our business. The Department of Fisheries and Oceans (“DFO”) administers the key habitat protection provision prohibiting any work or undertaking that would cause harm to fish or fish habitat. The Fisheries Act also prohibits the release of deleterious substances into waters frequented by fish. In terms of potential material adverse effects to our business resulting from a contravention of the Fisheries Act, enforcement of the habitat protection and pollution prevention provisions of the Fisheries Act is carried out through inspections to monitor or verify compliance, investigations of violations, issuance of warning, directions by Fishery Inspectors, authorizations and Ministerial orders, and court actions, such as injunctions, prosecution, court orders upon conviction and civil suits for recovery of costs.
Canadian Environmental Assessment Act, 2012. The Canadian Environmental Assessment Act, 2012 (the “CEAA”) is the primary federal statute for environmental assessments. The CEAA requires that an environmental assessment for projects that are listed in the Regulations Designating Physical Activities be completed prior to federal authorities making decisions that allow a project to proceed (i.e. prior to issuing certain licenses, disposing of federal lands, providing funding for a project). Projects that require an environmental assessment under the CEAA include, among others, the construction, operation, decommissioning and abandonment, in a wildlife area or a migratory bird sanctuary, of a new mine; the construction, operation, decommissioning and abandonment of a new dam or dyke or the expansion of an existing dam or dyke in certain circumstances; the construction, operation, decommissioning and abandonment of a new structure for the diversion of certain amounts of water; and the construction, operation, decommissioning and abandonment of a new coal mine with a coal production capacity of 3,000 t/day or more.
Canadian Environmental Protection Act, 1999. The Canadian Environmental Protection Act, 1999 (the “CEPA”) focuses on the prevention and management of risks posed by toxic and other harmful substances, as well as management of environmental and human health impacts of hazardous wastes, environmental emergencies and other sources of pollution. Certain substances used and/or produced, as well as downstream wastes generated through the course of our mining and processing operations may bring our business under the purview of the CEPA. The CEPA provides the authority to carry out inspections and investigations to ensure that regulations made under the CEPA and the CEPA itself are followed. Similar to the enforcement provisions of other environmental laws and regulations discussed herein, enforcement tools under the CEPA may include warnings, directions to prevent releases, tickets, orders requiring remedial measures, injunctions, prosecution, and financial penalties. Subject to the specific circumstances of a contravention of the CEPA, an enforcement action taken under the CEPA has the potential to cause a material adverse effect to our business.
Species at Risk Act. The purposes of the Species at Risk Act (the “SARA”) are to prevent wildlife species in Canada from disappearing, to provide for the recovery of wildlife species that no longer exist in the wild in Canada, endangered, or

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threatened as a result of human activity, and to manage species of special concern to prevent them from becoming endangered or threatened. The SARA may affect our operations if a species at risk is found at any time throughout the year on a property in Canada in which we have an interest. As with the protection of endangered species legislation in the US, identification of a species at risk may cause us to modify mining plans or develop and implement protection plans to avoid or minimize impacts to species protected by the SARA; however, we do not believe that there are any species protected under the SARA that would materially and adversely affect our ability to mine coal from our properties.
Migratory Birds Convention Act, 1994. Environment Canada is responsible for implementing the Migratory Birds Convention Act, 1994 (the “MBC Act”), which provides for the protection and conservation of migratory bird populations by regulating potentially harmful human activities. The MBC Act prohibits, among other things, the deposit of harmful substances in waters or areas frequented by migratory birds and a permit must be issued for all activities affecting migratory birds. Any person that commits an offence under the MBC Act is liable to a fine or to imprisonment. A contravention of the MBC Act may result in cancellation or suspension of a permit issued under the MBC Act and a compensatory order for costs incurred by others as a result of a contravention may be issued.
Climate Change Legislation and Regulations. Similar to climate change legislation, regulations, and proposals in the US, the direct and indirect costs of various GHG regulations, existing and proposed in Canada, may adversely affect our business. Equipment that meets future emission standards may not be available on an economic basis and other compliance methods to reduce our emissions or emissions intensity to future required levels may significantly increase operating costs or reduce output. Offset, performance or fund credits may not be available for acquisition or may not be available on an economic basis. Any failure to meet emission reduction compliance obligations may materially adversely affect our business and result in fines, penalties and the suspension of operations. There is also a risk that one or more levels of government could impose additional emissions or emissions intensity reduction requirements or taxes on emissions created by us or by consumers of our products. The imposition of such measures might negatively affect our costs and prices for our products and have an adverse effect on earnings and results of operations.
Alberta’s Climate Change and Emissions Management Act (the “CCEM Act”) and its accompanying Specified Gas Emitters Regulation (the “SGE Regulation”) requires a reduction in GHG emissions intensity for certain large GHG emitting facilities in Alberta. This system features emissions trading between regulated facilities and allows the use of offsets generated by projects in Alberta. Generally, the SGE Regulation establishes that companies emitting more than 100,000 tons of direct emissions in 2003, 2004, 2005, and 2006 in commercial operation must reduce their net emissions intensity by 12%. New facilities must reduce their emissions by 2% per year, beginning on their 4th year of operation. There are financial penalties for non-compliance for every ton of carbon dioxide equivalent over a facility’s net emission intensity limit as well as for contraventions of other provisions contained in the SGE Regulation.
Future federal legislation, including the implementation of potential international requirements enacted under Canadian law, as well as provincial emissions reduction requirements, may require the reduction of GHG or other industrial air emissions, or emission intensity, from our operations and facilities. Mandatory emissions reduction requirements may result in increased operating costs and capital expenditures. We are unable to predict the impact of emissions reduction legislation on our business and it is possible that such legislation may have a material effect on our business, financial condition, results of operations and cash flows.
Power Segment
General
We own two coal-fired power-generating units in Weldon, North Carolina with a total capacity of approximately 230 megawatts, which we refer to collectively as ROVA. We built ROVA, which commenced operations in 1994, as a Public Utility Regulatory Policies Act co-generation facility to supply Dominion North Carolina Power (“DNCP”). ROVA is held by our wholly-owned subsidiary Westmoreland Partners. All of the tangible and intangible assets of Westmoreland Partners are encumbered by liens securing our 8.75% Notes and WCC Term Loan Facility.
Coal Supply
ROVA purchases coal under short-term contracts from coal suppliers with identified reserves located in Central Appalachia, and supplies the power it produces to DNCP.
Customer
ROVA supplies a portion of the power it produces to DNCP and generates revenues from such sales, as well as through the settlement of related power hedging arrangements. In 2015, the sale of power by ROVA to DNCP accounted for approximately 6% of our consolidated revenues. The Power Segment is impacted by seasonality due to the impact of weather

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on customer demand and scheduled maintenance outages typically performed in the spring and fall, as well as the hedging agreement described below.
Westmoreland Partners is party to a consolidated power purchase and operating agreement (the “Consolidated Agreement”) with Virginia Electric Power Company that is scheduled to terminate in March 2019. The Consolidated Agreement provides for the sale to DNCP and its affiliates of all of ROVA’s net electrical output and dependable capacity. The Consolidated Agreement permits Westmoreland Partners to mitigate its cash losses through the sale to DNCP of substitute power not produced by ROVA during periods when it is uneconomical to operate the ROVA units. Under the Consolidated Agreement, we forego dispatching the ROVA units in low demand periods and maintain them in idle status. During such low demand periods, we meet DNCP’s power needs with fixed-price purchased power when doing so is more economically attractive than our physically operating the ROVA plants to generate power. Alternatively, we operate the ROVA plants, sell our produced power to DNCP and resell the fixed-price purchased power in the open market. When we operate the ROVA plants and resell our fixed-price purchased power into the open market, any such resales are made at prevailing market rates. In the event that the prevailing market price for power falls below the level of our hedged position during periods when we are reselling the fixed-price purchased power in the open market, those resales result in losses to us. The fixed-price purchased power contracts cover the period from April 2014 to March 2019 and contracted power prices range from $41.05 to $55.20 megawatts per hour, with a weighted average contract price of $43.93 over the remaining contract lives. For the year ended December 31, 2015, we incurred losses related to these hedging arrangements of $5.6 million. Based on current market pricing trends, we expect to experience losses from time to time under these hedging arrangements when the market price for power is not commensurate with our hedged position. Further, we are required to post collateral to cover certain projected long-term losses under these hedging arrangements based on the market price for power. The amount of such collateral may be significant and may negatively impact our liquidity. See “Risk Factors - Risks Relating to our Business and Operations - Our hedging arrangement related to our ROVA facility may result in losses if the market price for power drops below the level of our hedged position and, under certain circumstances, requires us to post additional collateral.”
During the fourth quarter of 2015 we evaluated our ROVA asset group for impairment primarily as a result of an impairment indicator related to the continued decline in forecasted electricity prices. We believe the depressed power prices will persist in the future. The asset group is comprised of property, plant, and equipment and related capital spares used to generate electricity. Our evaluation concluded that the long-lived assets at ROVA were impaired, and the carrying value of those assets was written down to zero as a result of an impairment charge of $133.1 million, with the charge included in the Loss on Impairment line item on the Consolidated Statement of Operations for the year ended December 31, 2015.
Heritage Segment
Our Heritage Segment includes the cost of heritage benefits we provide to former mining operation employees. The heritage costs consist of payments to our retired workers for medical benefits, workers’ compensation benefits, black lung benefits and combined benefit fund premiums to plans for United Mine Workers of America (“UMWA”) retirees required by statute. Canadian heritage costs include retiree medical benefits, statutory workers’ compensation premiums, and contributions to pension plans.
Corporate Segment
Our Corporate Segment includes primarily corporate administrative expenses and also includes business development expenses. In addition, the Corporate Segment contains our captive insurance company, WRM, through which we have elected to retain some of our operating risks. WRM provides our primary layer of property and casualty insurance in the United States. By using this insurance subsidiary, we have reduced the cost of our property and casualty insurance premiums and retained some economic benefits due to our excellent loss record. We reduce our major exposure by insuring for losses in excess of our retained limits with a number of third-party insurance companies.
Available Information
We file annual, quarterly and current reports, proxy statements and other information with 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.westmoreland.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 (303) 992-6463 or by mail at Westmoreland Coal Company, 9540 South Maroon Circle, Suite 200, Englewood, Colorado, 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.
This report, including Management’s Discussion and Analysis of Financial Condition and Results of Operation, contains forward-looking statements that may be materially affected by numerous risk factors, including those summarized below.
Risks Relating to our Business and Operations
Long-term sales and revenues could be significantly affected by environmental regulations and the effects of the environmental lobby.
Environmental regulations that are becoming 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 US coal plants by 2020. They are taking particular interest in Colstrip Units 1 and 2 and are actively lobbying the EPA to require cost-prohibitive pollution control equipment. In litigation filed in 2012, the activists stated that the EPA’s Best Available Retrofit Technology (“BART”) analysis for regional haze provides support for a determination that additional controls are necessary to achieve BART in the State of Montana. In June of 2015, the U.S. Court of Appeals for the Ninth Circuit found that EPA had failed to adequately explain its decision to require less stringent emission control technology for nitrogen oxides at Colstrip, and vacated the BART analysis and remanded it to the EPA for further proceedings. The EPA has not yet taken any action on a new regional haze plan. In 2013, environmental groups also filed a citizen suit complaint in Montana district court asserting that the owners and operators of Colstrip are in violation of Clean Air Act requirements. Trial in the case has been reset for May 2016. If environmental groups are successful, Colstrip would be required to undergo new permitting and comply with more stringent emission limits applicable to a number of pollutants. If additional emissions controls and upgrades are required at Colstrip Units 1 and 2, it is possible the owners could elect to shut down the units in lieu of making the large capital expenditures required to comply. If such a decision were made, we could lose coal sales of approximately 3.0 million tons per year. The loss of the sale of this tonnage at our Colstrip Mine could have a material adverse effect on the mine’s revenues and profitability.
Additionally, 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 sought regulatory approval to convert Unit 3 at Naughton to 100% natural gas fueling. When complete, the conversion of Unit 3 to natural gas will result in the loss of coal sales at our Kemmerer Mine. However, Rocky Mountain Power recently announced the conversion of Naughton Unit 3 will not occur until 2018. 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 conversion 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 or decreased operations 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 U.S. Army Corps of Engineers 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. 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.
We are also affected by Canadian GHG emissions regulations. On September 12, 2012, the federal government of Canada released final regulations for reducing GHG emissions from coal-fired electricity generation: “Reduction of Carbon Dioxide Emissions from Coal-Fired Generation of Electricity” (the “Canadian CO2 Regulations”). The Canadian CO2 Regulations required certain Canadian coal-fired electricity generating plants, effective July 1, 2015, to achieve an average annual emissions intensity performance standard of 463 tons of CO2 per gigawatt hour. The impact of the Canadian CO2 Regulations on existing plants will vary by province and specific location. The Prairie Operation’s long-term sales could be reduced unless certain existing plants that it supplies or new plants built to replace such existing plants are equipped with carbon capture and sequestration or other technology that achieves the prescribed performance standard, the impact of the Canadian CO2 Regulations is altered by equivalency agreements, or the Canadian CO2 Regulations are changed to lower the performance standard.
In addition, various Canadian provincial governments and other regional initiatives are moving ahead with GHG reduction and other initiatives designed to address climate change. As it is unclear at this time what shape additional regulation in Canada will ultimately take, it is not yet possible to reliably estimate the extent to which such regulations will impact the operations we acquired in the Canadian Acquisition. However, our Canadian Operations involve large facilities, so the setting

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of emissions targets (whether in the manner described above or otherwise) may well affect some or all of our Canadian customers, and may in turn have a material adverse effect on our business, results of operations and financial performance. In addition to directly emitting GHGs, our Canadian Operations require large quantities of power. Future taxes on or regulation of power producers or an increase in cost of the fuels used in power production (including coal, oil and gas or other products) may also add to our operating costs.

We have a substantial amount of indebtedness, which may adversely affect our cash flow and our ability to operate our business.
We have a substantial amount of indebtedness. At December 31, 2015, we had a total outstanding indebtedness of approximately $1,046 million, including (i) $350 million in principal amount of 8.75% Notes, (ii) $327.2 million in principal amount under the WCC Term Loan Facility, (iii) $299.2 million WMLP Term Loan and (iv) $19.8 million of supported letters of credit under the WCC Revolving Credit Facility, respectively, leaving $28.2 million of undrawn availability thereunder. Our substantial amount of indebtedness could have important consequences. For example, it could:
increase our vulnerability to adverse economic, industry or competitive developments;
result in an event of default if we fail to satisfy our obligations with respect to the 8.75% Notes, the WCC Term Loan Facility, the WCC Revolving Credit Facility or other debt or fail to comply with the financial and other restrictive covenants contained in the 8.75% Notes, the WCC Term Loan Facility, the WCC Revolving Credit Facility Agreement or agreements governing our other indebtedness, which event of default could result in all of our debt becoming immediately due and payable and could permit our lenders to foreclose on our assets securing such debt or otherwise recover that debt from us;
require a substantial portion of cash flow from operations to be dedicated to the payment of principal, premium, if any, and interest on our indebtedness, therefore reducing our ability to use our cash flow to fund our operations, capital expenditures and future business opportunities;
make it more difficult for us to satisfy our obligations with respect to the 8.75% Notes, the WCC Term Loan Facility and the WCC Revolving Credit Facility;
increase our cost of borrowing;
restrict us from making strategic acquisitions or causing us to make non-strategic divestitures;
limit our ability to service our indebtedness, including the 8.75% Notes, the WCC Term Loan Facility and the WCC Revolving Credit Facility;
limit our ability to obtain additional financing for working capital, capital expenditures, debt service requirements, acquisitions and general corporate or other purposes;
limit our flexibility in planning for, or reacting to, changes in our business or the industry in which we operate, placing us at a competitive disadvantage compared to our competitors who are less highly leveraged and who therefore may be able to take advantage of opportunities that our leverage prevents us from exploiting; and
prevent us from raising the funds necessary to repurchase all 8.75% Notes tendered to us upon the occurrence of certain changes of control, which failure to repurchase would constitute a default under the 8.75% Notes.
The occurrence of any one of these events could have a material adverse effect on our business, financial condition, results of operations, prospects and our ability to satisfy our obligations under the 8.75% Notes, the WCC Term Loan Facility and the WCC Revolving Credit Facility.
In conjunction with our acquisition of the GP, WMLP entered into the WMLP Financing Agreement to refinance WMLP’s indebtedness. The WMLP Financing Agreement provides for up to $295 million of first priority secured term loans, with $175 million currently funded and maturing in December 2018. WMLP used its delayed draw availability of $120 million under the WMLP Financing Agreement to fund the Kemmerer Drop that took place on August 1, 2015. Additionally, there is an accordion feature that takes effect when the delayed draw term loan feature expires which makes a further $150 million available for use to fund acquisitions during the remaining three years until the maturity of the WMLP Loan. Although the WMLP Loan will be consolidated in our financial statements due to our ownership of the GP and controlling interest in WMLP, neither Westmoreland nor any of its restricted subsidiaries will be obligors under the WMLP Financing Agreement and the WMLP Loan will be non-recourse to Westmoreland and its wholly owned subsidiaries.
If we further increase our indebtedness, the related risks that we now face, including those described above, could intensify.

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If we fail to comply with certain covenants in our various debt arrangements, it could negatively affect our liquidity and ability to finance our operations.
Our lending arrangements contain, among other terms, events of default and various affirmative and negative covenants. Should we be unable to comply with any future debt-related covenant, we will be required to seek a waiver of such covenant to avoid an event of default. Covenant waivers and modifications may be expensive to obtain, or, potentially, unavailable. If we are in breach of any covenant and are unable to obtain covenant waivers and our lenders accelerate our debt, we could attempt to refinance the debt or repay the debt by selling assets and applying the proceeds from such sales to the debt. Sales of assets undertaken in response to such immediate needs may be prohibited under our lending arrangements without the consent of our lenders, may be made at potentially unfavorable prices, or asset sales may not be sufficient to refinance or repay the debt, and we may be unable to complete such transactions in a timely manner, on favorable terms, or at all.
We may not generate sufficient cash flow at our operating subsidiaries to pay our operating expenses, meet our debt service costs and pay our heritage and corporate costs.
Our ability to fund our operations and to make scheduled payments on our indebtedness will depend on our ability to generate cash in the future. Our historical financial results have been, and we expect our future financial results to be, subject to substantial fluctuations, and will depend upon general economic conditions and financial, competitive, legislative, regulatory and other factors that are beyond our control. We may not be able to maintain a level of cash flow from operating activities sufficient to permit us to pay the principal and interest on the 8.75% Notes, the WCC Term Loan Facility or our other indebtedness.
If our cash flow and capital resources are insufficient to meet our debt service obligations or to fund our other liquidity needs, we may need to refinance all or a portion of our debt before maturity, seek additional equity capital, reduce or delay scheduled expansions and capital expenditures or sell material assets or operations. We cannot assure you that we would be able to refinance or restructure our indebtedness, obtain equity capital or sell assets or operations on commercially reasonable terms or at all. In addition, the terms of existing or future debt instruments may limit or prevent us from taking any of these actions. Our inability to take these actions and to generate sufficient cash flow to satisfy our debt service and other obligations could have a material adverse effect on our business, financial condition, results of operations and prospects.
If we cannot make scheduled payments on our debt or are not in compliance with our covenants and are not able to amend those covenants, we will be in default and holders of the 8.75% Notes and the lenders under the WCC Term Loan Facility and the WCC Revolving Credit Facility could declare all outstanding principal and interest to be due and payable, the lenders under the WCC Revolving Credit Facility could terminate their commitments to loan money to us, the holders of the 8.75% Notes and the lenders under the WCC Term Loan Facility and the WCC Revolving Credit Facility could foreclose on the assets securing our debt to them and we could be forced into bankruptcy or liquidation. If we are not able to generate sufficient cash flow from operations, we may need to seek an amendment to the 8.75% Notes, the WCC Term Loan Facility or the WCC Revolving Credit Facility to prevent us from potentially being in breach of our covenants. Such amendments, waivers or other modifications to our debt instruments may be expensive to obtain or potentially unavailable. If we are unable to obtain such an amendment, waiver or other modification, and our lenders accelerate our debt, we could attempt to refinance the debt or repay the debt by selling assets and applying the proceeds from such sales to the debt. Sales of assets undertaken in response to such immediate needs may be prohibited under our lending arrangements without the consent of our lenders, may be made at potentially unfavorable prices, or asset sales may not be sufficient to refinance or repay the debt, and we may be unable to complete such transactions in a timely manner, on favorable terms, or at all.
As a mine mouth operator, we provide coal to a small group of customers. This dependence could adversely affect our revenues if such customers reduce or suspend their coal purchases or if they become unable to pay for our coal.
In 2015, our Coal - U.S. Segment derived approximately 75% of its total revenues from coal sales to five power plants: Colstrip Units 3&4 (26%); Limestone Generating Station (16%); American Electric Power Company, Inc. (13%), Colstrip Units 1&2 (11%); and Pacificorp Energy, Inc. (9%). Our Coal - Canada Segment derived approximately 80% of its total revenues from coal sales to two customers and one country: SaskPower (42%), the country of Japan (22%) and ATCO Power (17%). WMLP derived approximately 58% of its total coal revenues from sales to two customers: American Electric Power Company, Inc. (42%) and Pacificorp Energy, Inc. (16%). A portion of these sales were facilitated by coal brokers. Interruption in the purchases of coal by our principal customers could significantly affect our revenues.
Unscheduled maintenance outages or other outages at our customers’ power plants, unseasonably moderate weather, higher-than-anticipated hydro seasons or increases in the production of alternative clean-energy generation such as wind power, or decreases in the price of competing fossil fuels such as natural gas, could cause our customers to reduce their purchases. Ten of our 12 mines are dedicated to supplying customers located adjacent to or near the mines, and these mines may have difficulty identifying alternative purchasers of their coal if their existing customers suspend or terminate their purchases.

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Additionally, certain of our long-term contracts are set to expire in the next several years. Our contracts with the Sherburne County Station are three-year rolling contracts, with one-third of the tonnage expiring on an annual basis. We have no tons under contract at this station after 2016. Our contract with Coyote Station, located adjacent to our Beulah mine and averaging approximately 2.5 million tons of coal sold per year, expires in May 2016 and is not expected to be renewed. Our contract with Colstrip Units 3 & 4 expires in December 2019. 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 the affected mine should the mine be unable to execute a new long-term coal supply agreement. The long term agreements we acquired or subsequently negotiated in connection with the Canadian Acquisition have long-remaining terms. Coal supply agreements also typically contain force majeure provisions allowing temporary suspension of performance by us or the customer during the duration of specified events beyond the control of the affected party. Such agreements may also prohibit us from passing certain increased costs resulting from changes in regulations to our customers. Additionally, many of our coal supply agreements contain provisions allowing customers to suspend acceptance of coal shipments if coal delivered does not meet certain quality thresholds.
Similarly, interruption in the purchase of power by DNCP could also negatively affect our revenues. During the year ended December 31, 2015, the sale of power by ROVA to DNCP accounted for approximately 6% of our consolidated revenues. Although ROVA supplies power to DNCP under long-term power purchase agreements, if DNCP is unable or unwilling to pay for the power produced by ROVA in a timely manner, it could have a material adverse effect on our results of operations, financial condition, and liquidity.
WMLP also sells a material portion of its coal under supply contracts. For the year ended December 31, 2015, approximately 87% of WMLP's coal production was sold under long-term supply contracts. When WMLP’s current contracts with customers expire, its customers may decide not to extend existing contracts or enter into new contracts. In 2015, 1.7 million tons are to be priced based on market indices, and from 2016 to 2018, 2.4 million tons are dependent upon reaching agreement during reopener periods.
Price adjustment, “price re-opener” and other similar provisions in WMLP’s 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 WMLP’s business, financial condition and/or results of operations.
In the absence of long-term contracts, WMLP’s 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, which would negatively affect WMLP’s ability to have sufficient cash to pay distributions and, in turn, would negatively affect our cash flow.
Our hedging arrangement related to our ROVA facility may continue to result in losses when the market price for power drops below the level of our hedged position and, under certain circumstances, requires us to post additional collateral.
The Consolidated Agreement with respect to our ROVA facility provides for the sale to DNCP and its affiliates of all of ROVA’s net electrical output and dependable capacity. The Consolidated Agreement permits Westmoreland Partners to mitigate its cash losses through the sale to DNCP of fixed-price purchased power, during periods when it is uneconomical to operate the ROVA units. Under the Consolidated Agreement, we forego dispatching the ROVA units in low demand periods and maintain them in idle status. During such low demand periods, we meet DNCP’s power needs with fixed-price purchased power when doing so is more economically attractive than our physically operating the ROVA plants to generate power. Alternatively, we operate the ROVA plants, sell our produced power to DNCP and resell the fixed-price purchased power in the open market. When we operate the ROVA plants and resell our fixed-price purchased power into the open market, any such resales are made at prevailing market rates. In the event that the prevailing market price for power falls below the level of our hedged position during periods when we are reselling the fixed-price purchased power in the open market, those resales result in losses to us. During 2015, we incurred losses related to these hedging arrangements of $5.6 million. Based on current market pricing trends, we expect to experience losses from time to time under these hedging arrangements when the market price for power is not commensurate with our hedged position.
Further, we are required to post collateral to cover certain projected long-term losses under these hedging arrangements based on the market price for power. The amount of such collateral may be significant and may negatively impact our liquidity.


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Our ability to collect payments from our customers could be impaired if their creditworthiness deteriorates.
Our ability to receive payment for coal sold and delivered depends on the continued creditworthiness of our customers. 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 this occurs, we may decide to sell the customer’s coal on the spot market, which may be at prices lower than the contracted price, or we may be unable to sell the coal at all. Furthermore, the bankruptcy of any of our customers could materially and adversely affect our financial position. In addition, competition with other coal suppliers could cause us to extend credit to customers and on terms that could increase the risk of payment default.
In addition, WMLP sells some of its coal to brokers who may resell its coal to end users, including utilities. These coal brokers may have only limited assets, making them less creditworthy than the end users. Under some of these arrangements, WMLP has 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 WMLP’s customers, whether an end user or a broker, could negatively affect WMLP's ability to have sufficient cash to pay distributions and, in turn, would negatively affect our cash flow.
Volatility in the equity markets or interest rate fluctuations could substantially increase our pension funding requirements and negatively impact our financial position.
At December 31, 2015, the projected benefit obligation under our defined benefit pension plans was $181.4 million and the fair value of plan assets was $141.1 million. The difference between plan obligations and assets, or the funded status of the plans, significantly affects the net periodic benefit cost and ongoing funding requirements of those plans. Among other factors, changes in interest rates, mortality rates, early retirement rates, investment returns and the market value of plan assets can affect the level of plan funding, cause volatility in the net periodic benefit cost and increase our future funding requirements. During the fiscal year ended 2015, we made $3.7 million in contributions to these pension plans and accrued $0.2 million in expenses related thereto. The current economic environment increases the risk that we may be required to make even larger contributions in the future.
If our assumptions regarding our future expenses related to employee benefit plans are incorrect, then expenditures for these benefits could be materially higher than we have assumed. In addition, we may have exposure under those plans that extend beyond what our obligations would be with respect to our own employees.
We provide various postretirement medical benefits and workers’ compensation benefits to current and former employees and their dependents. We calculate the total accumulated benefit obligations according to guidance provided by U.S. Generally Accepted Accounting Principles ("GAAP"). We estimate the present value of our postretirement medical, black lung and workers’ compensation benefit obligations to be $299.4 million, $17.8 million and $5.7 million, respectively, at December 31, 2015. In respect of our Canadian Operations we have an obligation to provide postretirement health coverage for eligible current union employees, as described in greater detail below. We have estimated these unfunded obligations based on actuarial assumptions and if our assumptions do not materialize as expected, cash expenditures and costs that we incur could be materially different.
Moreover, regulatory changes could increase our obligations to provide these or additional benefits. We participate in defined benefit multi-employer funds that were established in connection with the Coal Act, which provides for the funding of health and death benefits for certain UMWA retirees. Our contributions to these funds totaled $1.8 million and $2.0 million for the years ended December 31, 2015 and 2014, respectively. Our contributions to these funds could increase as a result of a shrinking contribution base as a result of the insolvency of other coal companies that currently contribute to these funds, lower than expected returns on fund assets or other funding deficiencies.
We could also have obligations under the Tax Relief and Health Care Act of 2006, (“2006 Act”). The 2006 Act authorized up to a maximum of $490 million in federal contributions to pay for certain benefits, including the healthcare costs under certain funds created by the Coal Act for “orphans,” i.e. retirees from companies that subsequently ceased operations, and their dependents. However, if Congress were to amend or repeal the 2006 Act or if the $490 million authorization were insufficient to pay for these healthcare costs, we, along with other contributing employers and certain affiliates, would be responsible for the excess costs.
We also contribute to a multi-employer defined benefit pension plan, the Central Pension Fund of the Operating Engineers, ("Central Pension Fund") on behalf of employee groups at our Colstrip, Absaloka and Savage mines that are represented by the International Union of Operating Engineers. The Central Pension Fund is subject to certain funding rules contained in the Pension Protection Act of 2006 (“PPA”). Under the PPA, if the Central Pension Plan fails to meet certain minimum funding requirements, it would be required to adopt a funding improvement plan or rehabilitation plan. If the Central Pension Fund adopted a funding improvement plan or rehabilitation plan, we could be required to contribute additional amounts to the fund. As of January 31, 2015, its last completed fiscal year, the Central Pension Fund reported that it was underfunded. If we were to partially or completely withdraw from the fund at a time when the Central Pension Fund were

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underfunded, we would be liable for a proportionate share of the fund’s unfunded vested benefits, and this liability could have a material adverse effect on our financial position.
Through our Canadian Operations we have responsibility for obligations under certain pension plans related to certain of the acquired operations. We have evaluated these plans, and believe that certain of them may be underfunded by immaterial amounts.
We are obligated to make contributions to these plans based upon agreement with the plan members and collective bargaining agreements with the representative unions. Our future contributions to these defined benefit plans are made in accordance with applicable pension legislation and the Income Tax Act (Canada). Further contributions to the pension plans could be required based on actuarial valuations, agreements, the plan asset investment performance, and future legislated requirements.
 
Under Canadian provincial Workers’ Compensation legislation, we remain obligated to fund workers’ compensation benefits arising from workplace injuries, disease and death of current and former employees. This obligation is based on premiums assessed by the applicable Workers’ Compensation Board which may vary based on the claims experience of the employer. We may be required to contribute additional premiums in the future depending on the number and amount of claims.
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, foreign exchange rates and future commodity prices. The sampling, interpretations or assumptions underlying any reserve estimate may be incorrect, and the impact on the amount of reserves ultimately proven to be recoverable may be material. Should the mineralization and/or configuration of a deposit ultimately turn out to be significantly different from that currently envisaged, then the proposed mining plan may have to be altered in a way that could affect the tonnage and grade of the reserves mined and rates of production and, consequently, could adversely affect the profitability of the mining operations. In addition, short term operating factors relating to the reserves, such as the need for orderly development of ore bodies or the processing of new or different ores, may cause reserve estimates to be modified or operations to be unprofitable in any particular fiscal period. There can be no assurance that our projects or operations will be, or will continue to be, economically viable, that the indicated amount of minerals will be recovered or that they will be recovered at the prices assumed for purposes of estimating reserves.
Any inaccuracies in our estimates of our coal reserves could result in decreased profitability from lower than expected revenues or higher than expected costs.
Our future performance depends on, among other things, the accuracy of our estimates of our proven and probable coal reserves. Our reserve estimates are prepared by our engineers and geologists or by third-party engineering firms and are updated periodically. There are numerous factors and assumptions inherent in estimating the quantities and qualities of, and costs to mine, coal reserves, including many factors beyond our control, including 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 foreign exchange rates and future commodity prices;
assumptions concerning the timing for the development of the reserves; and
assumptions concerning equipment and productivity, future coal prices, operating costs, including for critical supplies such as fuel, tires and explosives, capital expenditures and development and reclamation costs.
As a result, estimates of the quantities and qualities of economically recoverable coal attributable to any particular group of properties, classifications of reserves based on risk of recovery, estimated cost of production, and estimates of future net cash flows expected from these properties may vary materially due to changes in the above factors and assumptions. Any inaccuracy in our estimates related to our reserves could result in decreased profitability from lower than expected revenues or higher than expected costs.

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If the assumptions underlying our reclamation and mine closure 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 calculated the total estimated reclamation and mine-closing liabilities according to the guidance provided by GAAP and current industry practice. Estimates of our total reclamation and mine-closing liabilities 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. Likewise, if our customers, some of whom are contractually obligated to pay certain reclamation costs, default on the unfunded portion of their contractual obligations to pay for reclamation, we could be forced to make these expenditures ourselves and the cost of reclamation could exceed any amount we might recover in litigation.
We estimate that our gross reclamation and mine-closing liabilities, which are based upon projected mine lives, current mine plans, permit requirements and our experience, were $419.8 million (on a present value basis) at December 31, 2015. Of these December 31, 2015 liabilities, our customers have assumed $94.9 million by contract. In addition, we held final reclamation deposits, received from customers, of approximately $77.4 million at December 31, 2015 to provide for these obligations. We estimate that our obligation for final reclamation that was not the contractual responsibility of others or covered by offsetting reclamation deposits was $247.5 million at December 31, 2015. We must recover this $247.5 million 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.
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. 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. 
Our coal mining operations are subject to external conditions that could disrupt operations and negatively affect our results of operations.
With the exception of the Buckingham mine and the San Juan mine, our coal mining operations are all surface mines. These mines are subject to conditions or events beyond our control that could disrupt operations, affect production, and increase the cost of mining at particular mines for varying lengths of time. These conditions or events include: unplanned equipment failures; geological, hydrological or other conditions such as variations in the quality of the coal produced from a particular seam; variations in the thickness of coal seams and variations in the amounts of rock and other natural materials that overlie the coal that we are mining; weather conditions; and competition and/or conflicts with natural gas and other resource extraction activities and production within our operating areas. For example, we have endured poor rail performance at the Absaloka mine and Coal Valley mine, a major blizzard at the Beulah mine, a trestle fire at the Beulah mine, an unanticipated replacement of boom suspension cables on one of our draglines, all of which interrupted deliveries. Major disruptions in operations at any of our mines over a lengthy period could adversely affect the profitability of our mines.
In addition, unplanned outages of draglines and extensions of scheduled outages due to mechanical failures or other problems occur from time-to-time and are an inherent risk of our coal mining business. Unplanned outages typically increase our operation and maintenance expenses and may reduce our revenues because of selling fewer tons of coal. As of December 31, 2015, seven of our 31 owned or operated draglines were not in use due to either equipment servicing or because the dragline was scheduled to be down based on the operational needs of our mines. When properly maintained, a dragline can operate for 40 years or longer. As of December 31, 2015, the average age of Westmoreland’s dragline fleet was 35 years. As our

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draglines, shovels and other major equipment age, we may experience unscheduled maintenance outages or increased maintenance costs, which would adversely affect our operating results.
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 because of selling fewer tons of coal. For example, the Conesville power plant, which is the largest customer of our Buckingham mine, experienced an unexpected shutdown in the first and second quarters of 2015. The plant was brought back into operation in the third quarter of 2015, but was subsequently taken back out of production to address vibration issues caused by a malfunctioning fan in one of the units. The Conesville plant ran at half its capacity until the necessary repairs were completed in early December 2015. We maintain business interruption insurance coverage at some of our mines 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. Additionally, our Beulah mine filed an intercompany business interruption claim with WRI, our captive insurance subsidiary, in the second quarter of 2015, which resulted in an increase in operating expenses in our Corporate Segment.
Our operations are vulnerable to natural disasters, operating difficulties and infrastructure constraints, not all of which are covered by insurance, which could have an impact on our productivity.
Mining and power operations are vulnerable to natural events, including blizzards, earthquakes, drought, floods, fire, storms and the possible effects of climate change. Operating difficulties such as unexpected geological variations could affect the costs and viability of our operations. Our operations also require reliable roads, rail networks, power sources and power transmission facilities, water supplies and IT systems to access and conduct operations. The availability and cost of infrastructure affects our capital expenditures, operating costs, and planned levels of production and sales.
We maintain insurance for some, but not all, of the potential risks and liabilities associated with our business. For some risks, we may not obtain insurance if we believe the cost of available insurance is excessive relative to the risks presented. As a result of market conditions, premiums and deductibles for certain insurance policies can increase substantially, and in some instances, certain insurance may become unavailable or available only for reduced amounts of coverage. As a result, we may not be able to renew our existing insurance policies or procure other desirable insurance on commercially reasonable terms, if at all. Although we maintain insurance at levels we believe are appropriate and consistent with industry practice, we are not fully insured against all risks. In addition, pollution and environmental risks and consequences of any business interruptions such as equipment failure or labor disputes generally are not fully insurable. Losses and liabilities from uninsured and underinsured events and delay in the payment of insurance proceeds could have a material adverse effect on our financial condition, results of operations and cash flows.
Mining in Northern Appalachia and the Illinois Basin is more complex and involves more regulatory constraints than mining in other areas of the United States.
The geological characteristics of Northern Appalachian and Illinois Basin coal reserves, such as depth of overburden and coal seam thickness, make them complex and costly to mine. As WMLP’s mines in these regions 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 WMLP’s business, financial condition and/or results of operations and its ability to make distributions to unit holders like us.
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.

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We are dependent on information technology and our systems and infrastructure face certain risks, including cybersecurity risks and data leakage risks.
We are dependent on information technology systems and infrastructure. Any significant breakdown, invasion, destruction or interruption of these systems by employees, others with authorized access to our systems, or unauthorized persons could negatively impact operations. There is also a risk that we could experience a business interruption, theft of information, or reputational damage as a result of a cyber-attack, such as an infiltration of a data center, or data leakage of confidential information either internally or at our third-party providers. While we have invested in the protection of our data and information technology to reduce these risks and periodically test the security of our information systems network, there can be no assurance that our efforts will prevent breakdowns or breaches in our systems that could adversely affect our business.
Our Absaloka mine benefited from Indian Coal Production Tax Credits. Our inability to execute a new agreement with a new partner will adversely affect the financial condition of the operation.
The ICTC, which our Absaloka mine historically benefited from, expired on December 31, 2014, and was renewed on December 18, 2015, expiring on December 31, 2016. We are seeking a new partner, but our results of operations will continue to be negatively affected during the interim period in which we do not have a partner to capitalize on the currently enacted ICTC. From 2009 through 2013, we experienced a yearly average of $3.1 million of income and $6.1 million of cash receipts from Absaloka’s participation in ICTC transactions.
Our future success depends upon our ability to continue acquiring and developing coal reserves that are economically recoverable and to raise the capital necessary to fund our expansion.
Our recoverable reserves decline as we produce coal. We have not yet applied for the permits to use all of the coal deposits under our mineral rights, and the government agencies may not grant those permits in a timely manner or at all. Furthermore, we may not be able to mine all of our coal deposits as efficiently as we do at our current operations. Our future success depends upon conducting successful exploration and development activities and acquiring properties containing economically recoverable coal deposits. 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. As we mine our coal and deplete our existing reserves, replacement reserves may not be available when required or, if available, we may not be capable of mining the coal at costs comparable to those characteristic of the depleting mines. These factors could have a material adverse effect on our mining operations and costs, and our customers’ ability to use the coal we mine.
We may not be able to successfully replace our reserves or grow through future acquisitions.
In recent years, we have expanded our operations by adding new mines and reserves through strategic acquisitions, and we intend to continue expanding our operations and coal reserves through additional future acquisitions. Our future growth could be limited if we are unable to continue making acquisitions, or if we are unable to successfully integrate the companies, businesses or properties we acquire. We may not be successful in consummating any acquisitions and the consequences of undertaking these acquisitions are unknown. Our ability to make acquisitions in the future could be limited by restrictions under our existing or future debt agreements, competition from other coal companies for attractive properties or the lack of suitable acquisition candidates.

Our cash flow depends, in part, on the available cash and distributions of WMLP.
We expect our partnership interests in WMLP to be significant cash-generating assets. Therefore, our cash flow will be dependent, to some extent, upon the ability of WMLP to make quarterly distributions to its unitholders, including us. WMLP may not have sufficient available cash each quarter to enable it to pay distributions, which would have a corresponding negative impact on us. The amount of cash WMLP can distribute on its units principally depends upon the amount of cash it generates from its operations, which will fluctuate from quarter to quarter based on, among other things:
the domestic and foreign supply and demand for coal;
the quantity and quality of coal available from competitors;
the prices under WMLP’s existing contracts where the pricing is tied to and adjusted periodically based on indices reflecting current market pricing;
competition for production of electricity from non-coal sources, including the price and availability of alternative fuels;
domestic air emission standards for coal-fueled power plants and the ability of coal-fueled power plants to meet these standards by installing scrubbers or other means;

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adverse weather, climate or other natural conditions, including natural disasters;
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;
market price fluctuations for sulfur dioxide emission allowances;
the level of capital expenditures it makes;
the cost of acquisitions;
its debt service requirements and other liabilities;
fluctuations in its working capital needs;
its ability to borrow funds and access the capital markets;
restrictions contained in the debt agreements to which it is a party; and
the amount of cash reserves established by its general partner.
Any adverse change in these and other factors could result in a decline in WMLP’s ability to have sufficient cash to pay distributions and, in turn, would negatively affect our cash flow.

Our tax position may be adversely affected by virtue of our interest in WMLP.

Our investment in WMLP may adversely affect our tax position.  Whether or not WMLP makes cash distributions to us, we will have income from our interest in WMLP, which may or may not be offset by deductions from WMLP and may or may not be sufficient to fund the taxes on such income.  Further, if WMLP has taxable income, we may be allocated a significant portion of that taxable income.  Additionally, if the Internal Revenue Service ("IRS") successfully contests the positions that WMLP takes, the results of that contest may result in additional taxable income being allocated to us.  We could also be subject to additional taxation by individual states in which we do not conduct business or have assets due to our investment in WMLP.

Our acquisition of the general partner of a publicly traded limited partnership may subject us to a greater risk of liability than ordinary business operations.
We own the general partner of WMLP, a publicly traded limited partnership. The general partner of WMLP may be deemed to have undertaken fiduciary obligations with respect to WMLP and its limited partners. Such fiduciary obligations may require a higher standard of conduct than ordinary business operations and, therefore, may involve a greater risk of liability, particularly when a conflict of interest is found to exist. Our control of the general partner of WMLP may increase the possibility of claims of breach of fiduciary duties, including claims brought due to conflicts of interest. Any liability resulting from such claims could be material.
Although we control WMLP through our ownership of the GP, the GP owes fiduciary duties to WMLP’s unitholders, which may conflict with the interests of our shareholders.
Conflicts of interest exist and may arise in the future as a result of the relationships between us and our affiliates, on the one hand, and WMLP and its limited partners, on the other hand. The directors and officers of the GP have fiduciary duties to manage WMLP in a manner beneficial to us, as the sole member of the GP. At the same time, the GP has fiduciary duties to manage the limited partnership in a manner beneficial to WMLP and its limited partners. The board of directors of the GP, and in certain cases the conflicts committee of the board, will resolve any such conflict and has broad latitude to consider the interests of all parties to the conflict. The resolution of these conflicts may not always be in our best interest. For example, conflicts of interest with WMLP may arise in the following situations:

the interpretation and enforcement of contractual obligations between us and our affiliates, on the one hand, and WMLP, on the other hand;
the determination of the amount of cash to be distributed to WMLP’s limited partners and the amount of cash to be reserved for the future conduct of WMLP’s business; and
the determination whether to make borrowings under the WMLP Revolving Credit Facility to pay distributions to its limited partners.
In addition, subject to certain conditions, the 8.75% Notes, the WCC Term Loan Facility and the WCC Revolving Credit Facility permit us to transfer certain assets, including in certain instances equity interests we hold in other entities, to WMLP and its subsidiaries. Provided that we comply with the applicable conditions, we may transfer a significant portion of

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our assets to WMLP and its subsidiaries, which will not be restricted subsidiaries or guarantors under the 8.75% Notes, WCC Term Loan Facility or borrowers under the WCC Revolving Credit Facility.
Because we own a controlling interest in WMLP, any internal control deficiencies at WMLP could impact our ability to accurately report our financial results or prevent fraud.
Effective internal controls are necessary for us to provide reliable financial reports and effectively prevent fraud. Because of inherent limitations, internal control over financial reporting may not prevent or detect misstatements. The consummation of the WMLP transactions expanded Westmoreland by adding a significant subsidiary with separate financial reporting. The addition of WMLP’s financial reporting may have adverse effects on our internal control over financial reporting.
The ongoing oversight of the operations of WMLP following the WMLP transactions could create additional risks to our disclosure controls that we may not foresee. WMLP is a separate, publicly traded master limited partnership, or MLP. However, due to our significant equity ownership in WMLP and ownership of the GP, we consolidate the results of WMLP in our public financial statements. To the extent WMLP’s internal control systems are deficient, the integrity of our financial statements and results could be affected and we could fail to meet our regulatory reporting obligations in a timely manner, which ultimately could harm our operating results.
Transportation impediments may hinder our current operations or future growth.
Certain segments of our current business, principally our Absaloka Mine and our Coal Valley Mine rely on rail transportation for the delivery of coal product to customers and ports. Our ability to deliver our product in a timely manner could be adversely affected by the lack of adequate availability of rail capacity, whether because of work stoppages, union work rules, track conditions or otherwise. In 2011, flooding conditions disrupted rail service to the Absaloka Mine, resulting in lost revenue. Rail or shipping transportation costs represent a significant portion of the total cost of coal for our customers, and the cost of transportation is a key factor in a customer’s purchasing decision. In addition, the Coal Valley Mine exports the majority of its production to the global seaborne market through a port facility in western Canada.
The unavailability of rail capacity and port 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. Port capacity is also restricted in certain markets. If transportation is restricted or is unavailable, we may be unable to sell into new markets and, therefore, the lack of rail or port capacity would hamper our future growth. We currently have sufficient committed port capacity to operate our export business, and additional port capacity is expected to be constructed in western Canada in the future. However, increases in transportation costs or the lack of sufficient rail or port capacity or availability could make our coal less competitive, or could result in coal becoming a less competitive source of energy in general, which could lead to reduced coal sales and/or reduced prices we receive for the coal. Our inability to timely deliver product or fuel switching due to rising transportation costs could have a material adverse effect on our business, financial condition and results of operations.
In addition, WMLP depends upon barge, rail and truck systems to deliver coal to its customers. Disruptions in transportation services due to weather-related problems, mechanical difficulties, strikes, lockouts, bottlenecks, and other events could impair WMLP’s ability to supply coal to its customers. 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 WMLP’s 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 WMLP’s ability to increase or to maintain production and could adversely affect its revenues.
Decreased availability or increased costs of key equipment and materials could impact our cost of production and decrease our profitability.
We depend on reliable supplies of mining equipment, replacement parts and materials such as explosives, diesel fuel, tires and magnetite. The supplier base providing mining materials and equipment has been relatively consistent in recent years, although there continues to be consolidation, which has resulted in a limited number of suppliers for certain types of equipment and supplies. Any significant reduction in availability or increase in cost of any mining equipment or key supplies could adversely affect our operations and increase our costs, which could adversely affect our operating results and cash flows.
In addition, the prices we pay for these materials are strongly influenced by the global commodities market. Coal mines consume large quantities of commodities such as steel, copper, rubber products, explosives and diesel and other liquid fuels. Some materials, such as steel, are needed to comply with regulatory requirements. 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.

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Our long-term coal contracts are "cost protected" in that they typically contain either full pass-through of our costs or 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.
WMLP enters into forward-purchase contract arrangements for a portion of its anticipated diesel fuel and explosive needs. Additionally, some of WMLP’s expected diesel fuel requirements are protected, in varying amounts, by diesel fuel escalation provisions contained in coal supply contracts with some of its 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 WMLP’s strategy provides it protection in the event of price increases to its diesel fuel, it may also prevent WMLP from the benefits of price decreases. If prices for diesel fuel decreased significantly below WMLP’s forward-purchase contracts, it would lose the benefit of any such decrease.
Our ability to acquire new permits and licenses in certain Canadian provinces may be affected by aboriginal rights.
Canadian courts have recognized that aboriginal peoples may have rights with respect to land used or occupied by their ancestors in the absence of treaties to address those rights. These aboriginal rights may vary from limited rights of use for traditional purposes to rights of title and will depend upon, among other things, the nature and extent of prior aboriginal use and occupation. Aboriginal peoples may also have rights under applicable treaties for harvesting and ceremonial purposes on Crown lands or lands to which they have rights of access. The provincial governments of Alberta and Saskatchewan, as well as the Canadian government, are required to consult with aboriginal peoples with respect to the granting of and the issuance or amendment of project authorizations, including approvals, permits and licenses. These requirements may affect the ability of our Canadian Operations to acquire new or amended operating approvals in these jurisdictions within a reasonable time frame, and may affect our development schedule and costs.
Union represented labor creates an increased risk of work stoppages and higher labor costs.
As of December 31, 2015, approximately 39% of our total U.S. workforce is represented by two labor unions, the International Union of Operating Engineers and the UMWA. Our unionized workforce is spread out amongst the majority of our surface mines. As a majority of our workforce is unionized, there may be an increased risk of strikes and other labor disputes, and our ability to alter labor costs is subject to collective bargaining. The collective bargaining agreement relating to the represented workforce at the Absaloka Mine expired on May 31, 2015 and was renegotiated through May 31, 2021. In 2012, we were successful in entering into agreements with our workforce at Savage, Kemmerer and Colstrip. If our Jewett Mine operations were to become unionized, we could be subject to additional risk of work stoppages, other labor disputes and higher labor costs, which could adversely affect the stability of production and our results of operations. We reached an agreement with the UMWA in December 2014 on a new collective bargaining agreement at the Beulah Mine to replace the existing agreement which expired on January 1, 2015. While strikes are generally a force majeure event in long-term coal supply agreements, thereby exempting the mine from its delivery obligations, the loss of revenue for even a short time could have a material adverse effect on our financial results.
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.
As of December 31, 2015, approximately 70% of our total Canadian workforce was represented by a labor union. There are labor agreements in place with one or more unions at each of the producing mines of our Canadian Operations, other than the Genesee Mine. If we are not successful in negotiating new labor agreements as they expire with any of the Canadian workforce unions or otherwise maintaining strong partnerships with them, it could result in labor disputes, work stoppages or higher labor costs, any of which could have an adverse effect on our business and results of operations.
When the Kemmerer Drop occurred, WMLP gained a partially unionized workforce. Now that WMLP's workforce is approximately 30% unionized, it could adversely affect its productivity and labor costs and increase the risk of work stoppages, all of which could adversely affect WMLP’s business, financial condition and/or results of operations.

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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.
As a result of the Canadian Acquisition, we are subject to foreign exchange risk as a result of exposures to changes in currency exchange rates between the U.S. and Canada.
As a result of the Canadian Acquisition, we face increased exposure to exchange rate fluctuations between the Canadian dollar and U.S. dollar. We realize a large portion of our revenues from sales made from the Canadian assets in Canadian dollars, and almost all of the expenses incurred by the Canadian assets are recognized in Canadian dollars. The exchange rate of the Canadian dollar to the U.S. dollar has been at or near historic highs in recent years but in the last quarter of 2014 and first quarter of 2015 weakened considerably and continued to weaken throughout 2015. If this weakening of the Canadian dollar in comparison to the U.S. dollar continues, earnings generated from our Canadian Operations will translate into reduced earnings in our consolidated statements of operations reported in U.S. dollars. In addition, our Canadian Subsidiaries also record certain accounts receivable and accounts payable, which are denominated in Canadian dollars. Foreign currency transactional gains and losses are realized upon settlement of these assets and obligations.
Fluctuations in the U.S. dollar relative to the Canadian dollar may make it more difficult to perform period-to-period comparisons of our reported results of operations. For purposes of accounting, the assets and liabilities of our Canadian Operations will be translated using period-end exchange rates, and the revenues and expenses of our Canadian Operations will be translated using average exchange rates during each period. Translation gains and losses are reported in accumulated other comprehensive loss as a component of stockholders’ equity.
Federal legislation could result in higher healthcare costs.
In March 2010, the Patient Protection and Affordable Care Act (the “PPACA”) was enacted, impacting our costs of providing healthcare benefits to our eligible active employees, with both short-term and long-term implications. In the short term, our healthcare costs could increase due to, among other things, an increase in the maximum age for covered dependents to receive benefits, changes to benefits for occupational disease related illnesses, the elimination of lifetime dollar limits per covered individual and restrictions on annual dollar limits per covered individual. In the long term, our healthcare costs could increase for these same reasons, as well as due to an excise tax on “high cost” plans, among other things. Implementation of this legislation is expected to extend through 2018.
Beginning in 2018, the PPACA will impose a 40% excise tax on employers to the extent that the value of their healthcare plan coverage exceeds certain dollar thresholds. We anticipate that certain governmental agencies will provide additional regulations or interpretations concerning the application of this excise tax. We will continue to evaluate the impact of the PPACA, including any new regulations or interpretations, in future periods.
Any increase in cost, as a result of legislation or otherwise, could adversely affect our business, financial condition and/or results of operations.
Certain federal income tax preferences currently available with respect to coal exploration and development may be eliminated in future legislation.
Among the changes contained in President Obama’s budget proposal (the “Budget Proposal”) is the elimination of certain key U.S. federal income tax preferences relating to coal exploration and development. The Budget Proposal would: (i) eliminate current deductions, the 60-month amortization period and the 10-year amortization period for exploration and development costs relating to coal and other hard mineral fossil fuels, (ii) repeal the percentage depletion allowance with respect to coal properties, (iii) repeal capital gains treatment of coal and lignite royalties and (iv) exclude from the definition of domestic production gross receipts all gross receipts derived from the production of coal and other hard mineral fossil fuels. The passage of any legislation effecting changes similar to those in the Budget Proposal in U.S. federal income tax laws could eliminate certain tax deductions that are currently available with respect to coal exploration and development, and any such change could increase our taxable income and negatively impact the value of an investment in our common stock.

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Risk Factors Relating to the Coal and Power Industries
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.
Competition in the North American coal industry may adversely affect our revenues and results of operations.
A few 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 future 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. The current restructuring of several North American coal producers may reduce our clarity into the competitive markets in which we sell coal for in the near term, and the long-term effect of such restructuring on our competitive position is unclear.
Any change in consumption patterns by utilities away from the use of coal could affect our ability to sell the coal we produce or the prices that we receive.
In addition to competing with other coal producers, we compete generally with producers of other fuels. In 2015, the electric utility industry accounted for the majority of coal consumption in the U.S. and Canada. The demand for electricity, environmental and other governmental regulations, and the price and availability of competing fuels for power plants such as nuclear, hydro, natural gas and fuel oil as well as alternative sources of energy affects the amount of coal consumed by the electric utility industry. A 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. We do not have contracts guaranteeing the purchase of fixed quantities of coal, so revenue can fall even though we have long-term contracts.
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. Similar legislation has been implemented or is under consideration in several Canadian provinces. Passage of these and other state, provincial 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, state or provincial 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 and Canada, 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.
Changes in the export and import markets for coal products could affect the demand for our coal, our pricing and our profitability.
Although our mines and the majority of our customers are located in North America, we compete in a worldwide market for coal and coal products. The pricing and demand for our products is affected by a number of global economic factors that are beyond our control and difficult to predict. These factors include:
currency exchange rates;
growth of economic development;
price of alternative sources of electricity or steel;

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worldwide demand for coal and other sources of energy; and
ocean freight rates.
Any decrease in the aggregate amount of coal exported from the United States and Canada, or any increase in the aggregate amount of coal imported into the United States and Canada, could have a material adverse impact on the demand for our coal, our pricing and our profitability. Ongoing uncertainty in European economies and slowing economies in China, India and Brazil have reduced and may continue to reduce near-term pricing and demand for coal exported from the United States and Canada. Coal Valley Mine primarily supplies premium thermal coal to the Asian export market. Ownership of this mine will increase our exposure to price fluctuations in the international coal market, and a substantial downturn in demand in the Asian market could have a material adverse effect on our financial condition and 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. We must compensate employees for work-related injuries. If we do not make adequate provision for our workers’ compensation liabilities, it could harm our future operating results. 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 and Canadian federal, state or provincial 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 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 the mine. These actions could adversely affect our business, financial condition and/or results of operations.
New legislation or regulations and orders may be adopted that may materially adversely affect our mining operations, our cost structure 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 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

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effect on our financial condition and results of operations. For additional information regarding specific regulations that impact our operations, see “Material Effects of Regulation - U.S. Regulation" and "Material Effects of Regulation - Canada Regulation."
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 announced a Climate Action Plan announced in June 2013, EPA issued in August 2015 final standards for GHG emissions from existing fossil-fuel fired power plants, as well as new, modified and reconstructed fossil-fuel fired power plants. The Clean Power Plan sets standards for existing sources as stringent state-specific carbon emission rates to be phased in between 2020 and 2030. The proposed rule would give states the discretion to use a variety of approaches - including cap-and-trade programs - to meet the standard. In February of 2016, however, the Supreme Court issued an order staying the Clean Power Plan pending judicial review of the rule by the U.S. Court of Appeals for the D.C. Circuit as potentially review by the Supreme Court. The D.C. Circuit issued an expedited briefing schedule for challenges to the rule, and oral argument is schedule for June of 2016. The U.S. Congress has considered, and in the future may again consider, legislation governing GHG emission, including “cap and trade” legislation that would establish a cap on emissions of GHGs covering much of the economy in the United States and would require most sources of GHG emissions to obtain GHG emission “allowances” corresponding to their annual emissions of GHGs. In addition, coal-fired power plants, including new coal-fired power plants or capacity expansions of existing plants, have become subject to opposition by environmental groups seeking to curb the environmental effects of GHG emissions. It is difficult to predict at this time the effect these proposed rules would have on our revenues and profitability. For additional information, see “Business - Material Effects of Regulation” in this report.
In Canada, in September 2012 the federal government released final regulations for reducing GHG emissions from coal-fired electricity generation through the Canadian CO2 Regulations. The Canadian CO2 Regulations required certain Canadian coal-fired electricity generating units, effective July 1, 2015, to achieve an average annual emissions intensity performance standard of 463 tons of CO2 per gigawatt hour. The performance standard applies to new units commissioned after July 1, 2015 and to units that are considered to have reached the end of their useful life at 50 years from the unit’s commissioning date. All of the customer generating assets currently served by the Prairie Operations have annual average CO2 emissions intensity greater than the performance standard other than one of the units at SaskPower’s Boundary Dam Generating Station, which incorporates carbon capture and sequestration technology. New and end-of-life units that incorporate technology for carbon capture and sequestration may apply for a temporary exemption from the performance standard that would remain in effect until 2025, provided that certain implementation milestones are met. Provincial equivalency agreements, under which the Canadian CO2 Regulations would stand down, are being negotiated or discussed with the provinces of Alberta and Saskatchewan. The Prairie coal production in the long-term could be reduced unless certain existing units or new units of the customers served by the Prairie operations are equipped with carbon capture and storage or other technology that achieves the prescribed performance standard, the impact of the Canadian CO2 Regulations is altered by equivalency agreements, or the Canadian CO2 Regulations are changed to lower the performance standard. The impact of the Canadian CO2 Regulations on existing units will vary by location and province.
In addition, various Canadian provincial governments and other regional initiatives are moving ahead with GHG reduction and other initiatives designed to address climate change. For example, under the Climate Change and Emissions Management Act, the Province of Alberta enacted the “Specified Gas Emitters Regulation.” As of January 1, 2008, this enactment requires certain existing facilities with direct emissions of 100,000 metric tons or more of certain specified gases to ensure that the net emissions intensity for a year for an established facility must not exceed 88% of the baseline emissions intensity for the facility. For the 2013 and 2014 compliance periods, Coal Valley Mine exceeded 88% of its baseline emissions and was required to contribute to the Climate Change and Emissions Management Fund by purchasing fund credits. For the 2015 compliance period, the preliminary calculations indicate Coal Valley Mine will not be required to purchase fund credits and could earn fund credits for future use by coming in under 88% of its baseline emissions. It is also anticipated that emissions intensity at Coal Valley Mine will be such that fund credits for future use will be earned, and fund credits will not be required to be purchased. The Government of Alberta has also introduced a complementary Specified Gas Reporting Regulation, which

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came into force on October 20, 2004. This legislation requires all industrial emitters emitting 50,000 tons or more of CO2 to report their annual GHG emissions in accordance with the specified Gas Reporting Standard published by the Government of Alberta. In Saskatchewan, Bill 126, The Management and Reduction of Greenhouse Gases Act, was passed in 2010 but is not yet proclaimed in force. The legislation provides a framework for the control of GHG emissions by regulated emitters and will be proclaimed once accompanying draft regulations are finalized. In Alberta, the Government commissioned the Alberta Climate Leadership Panel to make policy recommendations for Alberta to enact to combat climate change. On November 20th, 2015, the Alberta Climate Leadership Panel published a report entailing policy recommendations including the shutdown of coal-fired power generation by the year 2030 and changes to the SGE Regulation that would see costs of emissions to large emitters increase as early as 2017. The Government of Alberta has not yet presented legislation related to combatting climate change, but the Premier in a press conference has indicated that they will be implementing the shutdown and SGE Regulation changes proposed by the Alberta Climate Leadership Panel. The full effects of any new legislation is unknown until draft legislation is presented by the Alberta Government.
As it is unclear at this time what shape additional regulation in Canada will ultimately take, it is not yet possible to estimate the extent to which such regulations will impact our Canadian Operations. However, those operations involve large facilities, so the setting of emissions targets (whether in the manner described above or otherwise) may well affect them and may have a material adverse effect on our business, results of operations and financial performance. These developments in both Canada and the United States could have a variety of adverse effects on demand for the coal we produce. For example, laws or regulations regarding GHGs could result in fuel switching from coal to other fuel sources by electricity generators, or require us, or our customers, to employ expensive technology to capture and sequester carbon dioxide. Political and environmental opposition to capital expenditure for coal-fired facilities could affect the regulatory approval required for the retrofitting of existing power plants. For example, the Naughton power facility, which is located adjacent to the Kemmerer Mine, announced in April 2012 that it is seeking regulatory approval to switch Unit 3 to natural gas from coal. The conversion of Naughton Unit 3 to natural gas would result in significant reduction in coal sales from our Kemmerer Mine, and could have a material adverse effect on our results of operations. However, Rocky Mountain Power, the owner of the Naughton facility, recently announced that the conversion will not take place until at least 2018.
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.
In addition to directly emitting GHGs, our Canadian Operations require large quantities of power. Future taxes on or regulation of power producers or the production of coal, oil and gas or other products may also add to our operating costs. The policy recommendations put forward by the Alberta Climate Leadership Panel, if enacted, have the potential to increase costs of energy products used in the mine operations located in Alberta, such as diesel fuel, gasoline, oil, and electricity.
And many of the developments in the U.S. discussed above that may affect our customers and demand for our coal could also affect us directly through adverse impacts on ROVA.
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. The slowing pace at which permits are issued or renewed for new and existing mines has materially impacted production in Appalachia, but could also affect other regions in which WMLP operates. 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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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, and could impose additional costs on ROVA.
Our customers, as well as ROVA, 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. For example, the purchaser of coal produced from the Jewett Mine blends our lignite with compliance coal from Wyoming. Tightened nitrogen oxide and new mercury emission standards could result in the customer purchasing an increased blend of the Wyoming coal in order to reduce emissions. Further, increased market prices for sulfur dioxide emissions allowances and increased coal ash management costs could also favor an increased blend of the lower ash Wyoming compliance coal. In such a case, the customer has the option to increase its purchases of other coal and reduce purchases of our coal or terminate our contract. A termination of the contract or a significant reduction in the amount of our coal that is purchased by the customer could have a material adverse effect on our results of operations and financial condition. The EPA intends to issue or has issued a number of significant regulations that will impose more stringent requirements relating to air, water and waste controls on electric generating units. These rules include the EPA’s final rule for CCR management, announced in December 2014, that further regulates the handling of wastes from the combustion of coal. In addition, in February 2012, the EPA signed a rule to reduce emissions of mercury and toxic air pollutants from new and existing coal- and oil-fired electric utility steam generating units, often referred to as the MATS Rule. In June of 2015, the U.S. Supreme Court reversed the U.S. Court of Appeals for the D.C. Circuit’s decision upholding the rule and held that EPA had failed to properly consider costs when assessing whether to regulate fossil fuel-fired EGUs under the hazardous air pollutant provisions of the Clean Air Act. In June of 2015, the U.S. Supreme Court reversed the U.S. Court of Appeals for the D.C. Circuit and held that 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 EPA to conduct a cost assessment but without vacatur, allowing the rule to remain in effect while EPA conducts the rulemaking. On December 1, 2015, 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. EPA indicated that it expects to issue a final finding by April 15, 2016.
In April 2014, the U.S. Supreme Court upheld the EPA’s Cross-State Air Pollution Rule (“CSAPR”), which would require stringent reductions in emissions of nitrogen oxides and sulfur dioxide from power plants in much of the Eastern United States, including Texas and North Carolina, and in October 2014 the D. C. Circuit granted the EPA’s motion to lift the D.C. Circuit’s stay of the CSAPR, and remanded the case to the D.C. Circuit for further proceedings. In November, 2014 the EPA issued a ministerial rule aligning the CSAPR implementation dates with the Court’s order, with phase 1 reductions beginning in January 2015, and more stringent phase 2 reductions in January 2017. In July 2015, the D.C. Circuit remanded to EPA portions of the 2014 sulfur dioxide and ozone budgets on grounds the reductions were greater than necessary to reduce impacts on downwind states, but did not vacate any portion of the rule. The EPA has indicated that it will address these issues in future rulemakings, but that phase 1 reductions will begin in January 2015, with more stringent phase 2 reductions in January 2017as necessary.The In May 2014, the EPA Administrator signed a final rule that establishes requirements for cooling water intake structures for the withdrawal of cooling water by electric generating plants; the rule is anticipated to affect over 500 power plants.
Considerable uncertainty is associated with air emissions initiatives. New regulations are in the process of being developed, and many existing and potential regulatory initiatives are subject to review by federal or state agencies or the courts. Stringent air emissions limitations are either in place or are likely to be imposed in the short to medium term, and these limitations will likely require significant emissions control expenditures for many coal-fired power plants. For example, the owners of Units 3 and 4, adjacent to our Colstrip mine, are getting considerable pressure from environmental groups to install Selective Catalytic Reduction (“SCR”) technology. Should the owners be forced by the EPA to install such technology, the capital requirements could make the continued operation of the two units unsustainable. As a result, Colstrip and other similarly-situated 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.
The regulation of air emissions in Canada may also reduce the demand for the products of the operations we acquired in the Canadian Acquisition. Specifically, the Alberta Environmental Protection and Enhancement Act (“EPEA”) and its

47


Canadian Environmental Protection Act, 1999 (“CEPA, 1999”) and the provision for the reporting of pollutants via the National Pollutant Release Inventory (“NPRI”), could also have a significant effect on the customers of our Canadian mines, which in turn could, over time, significantly reduce the demand for the coal produced from those mines.
The customers of our Canadian mines must comply with a variety of environmental laws that regulate and restrict air emissions, including the EPEA and its regulations, and the CEPA, 1999. Because many of these customers’ activities generate air emissions from various sources, compliance with these laws requires our customers in Canada to make investments in pollution control equipment and to report to the relevant government authorities if any emissions limits are exceeded or are made in contravention of the applicable regulatory requirements.
These laws restrict the amount of pollutants that our Canadian customer’s facilities can emit or discharge into the environment. The NPRI, for example, is created under authority of the CEPA, 1999 and is a Canada-wide, legislated, and publicly accessible inventory of specific substances that are released into the air, water, and land. The purpose of the NPRI was to provide comprehensive national data on releases of specified substances, and assists with, identifying priorities for action, encouraging voluntary action to reduce releases, tracking the progress of reductions in releases, improving public awareness and understanding of substances released into the environment, and supporting targeted initiatives for regulating the release of substances.
Regulatory authorities can enforce these and other environmental laws through administrative orders to control, prevent or stop a certain activity; administrative penalties for violating certain environmental laws; and judicial proceedings. If environmental regulatory burdens continue to increase for our Canadian customers, as a result of policy changes or increased regulatory reform relating to the substances reported, it could potentially affect customer operations and future demand for coal.
 
Risk Factors Relating to our Equity
Provisions of our certificate of incorporation, bylaws, and Delaware law may have anti-takeover effects that could prevent a change of control of our company that stockholders may consider favorable, and the market price of our common stock may be lower as a result.
Provisions in our certificate of incorporation, bylaws and Delaware law could make it more difficult for a third party to acquire us, even if doing so might be beneficial to our stockholders. Provisions of our bylaws impose various procedural and other requirements that could make it more difficult for stockholders to bring about some types of corporate actions such as electing individuals to the board of directors. Our ability to issue preferred stock in the future may influence the willingness of an investor to seek to acquire our company. These provisions could limit the price that some investors might be willing to pay in the future for shares of our common stock and may have the effect of delaying or preventing a change in control. Provisions in the indenture governing the 8.75% Notes regarding certain change of control events could have a similar effect.

Risks Related to Our Acquisitions
The assets we acquired in the San Juan Acquisition may underperform relative to our expectations; the San Juan Acquisition may cause our financial results to differ from our expectations or the expectations of the investment community; and we may not be able to achieve anticipated cost savings or other anticipated objectives.
The success of the San Juan Acquisition will depend, in part, on our ability to integrate the San Juan Entities with our existing business. The integration process may be complex, costly and time consuming. The potential difficulties of integrating the San Juan Entities and realizing our expectations for the San Juan Acquisition include, among other things:
failure to implement our strategy for the development of the acquired assets;
unanticipated changes in commodity prices;
unanticipated changes in applicable laws and regulations;
retaining and obtaining required regulatory approvals, licenses and permits;
operating risks inherent in our business; and
other unanticipated issues, expenses and liabilities.
Many of these factors will be outside of our control, and any one of them could result in increased costs, decreases in the amount of expected revenues and diversion of management’s time and energy, which could materially impact our business,

48


financial condition and results of operations. In addition, even if our operations and the acquired assets are integrated successfully, we may not realize the full benefits of the San Juan Acquisition, including the synergies or cost savings that we expect. These benefits may not be achieved within the anticipated time frame, or at all. As a result, we cannot assure you that the San Juan Acquisition will result in the realization of the full benefits anticipated.
SJGS, San Juan’s primary customer, is required to shut down half of its power producing units at the end of 2017, which we expect will result in a significant decrease in SJGS’s demand for coal produced by the San Juan mine.
On October 1, 2014 SJGS reached an agreement with the New Mexico agencies, non-governmental organizations, and the EPA to shut down two of its power generating units by December 31, 2017 to comply with requirements under the Clean Air Act. Under the same agreement, SJGS also agreed to install selective non-catalytic reduction (“SNCR”) emission control technology on its two units that will remain active, with the deadline for that installation at the end of 2016. Following the shutdown of the units, four of SJGS’s nine owning utilities will cease ownership, with PSNM and Tucson Electric expected to remain as the primary customers of the station. In August 2015, the parties agreed to modifications to the original agreement. The modifications did not alter provisions requiring installation of SNCR or shut down of two of the units, but it did include a commitment by PSNM to make a filing before the New Mexico PRC demonstrating the ongoing economic viability of SJGS beyond 2022. This agreement has not yet been approved by the New Mexico PRC. As a result of these developments, we expect that SJGS’s demand for coal produced by the San Juan mine will decrease significantly, which will negatively impact our results of operations and financial condition unless we are able to find a suitable alternative customer for the coal produced by the San Juan mine. Because the San Juan mine is a mine-mouth facility, we may have difficulty identifying customers.
SJCC is subject to pending litigation that could result in the temporary interruption of its mining operations.
SJCC is subject to certain litigation related to its operations, including an Action filed by WildEarth Guardians (“WEG”) on February 27, 2013, in the United States District Court for the District of Colorado seeking review of the Office of Surface Mining (“OSM”) decisions and decisions of the Assistant Secretary of the Interior approving mine plans or mine plan amendments concerning seven separate coal mines in Colorado, Montana, New Mexico, and Wyoming. Among the decisions being challenged is the January 2008 approval of the mining plan modification for the San Juan Mine. WEG alleges that in approving the plans or plan amendments, OSM engaged in a “pattern and practice of failing to comply with” the requirements of the National Environmental Policy Act by failing “to ensure that the public was appropriately involved in the adoption of” the mine plans and by failing to “take a hard look at a number of potentially significant environmental impacts.” On February 7, 2014, the case was transferred to the U.S. District Court for the District of New Mexico. On March 14, 2014, WEG filed an amended petition. Settlement discussions among the parties are ongoing and no trial date has been scheduled. In the event the parties reach a settlement or litigation proceeds and WEG prevails in the case, there is the potential that San Juan would be required to cease mining activities, pending OSM’s completion of a supplemental environmental impact analysis that supports the Assistant Secretary of the Interior’s approval of the mining plan modification for the San Juan Mine in compliance with the National Environmental Policy Act. Any such interruption of mining activities at San Juan could have an adverse impact on our results of operations and financial condition.
We may not have uncovered all risks associated with our recent acquisition activity, and significant liabilities related to such activity of which we are not aware may exist now or arise in the future.
In connection with the San Juan, Canadian and Buckingham Acquisitions, and our acquisition of a controlling interest in WMLP, we assumed the risk of unknown, and certain known, liabilities. We may become responsible for unexpected liabilities that we failed or were unable to discover in the course of performing due diligence in connection with these acquisitions or for costs associated with known liabilities that exceed our estimates. Under the various purchase arrangements relating to these acquisitions, there may not be recourse to indemnification should we discover a previously unknown liability, whether material or immaterial.
We may not realize the anticipated benefits of recent or future acquisitions, potential synergies, due to challenges associated with integration and other factors.
The long-term success of the acquisitions will depend in part on the success of our management in efficiently integrating the operations, technologies and personnel acquired entities or operations. Our management’s inability to meet the challenges involved in successfully integrating acquired entities or operations or to otherwise realizing the anticipated benefits of such transactions could harm our results of operations.
The challenges involved in integration include:
integrating the operations, processes, people and technologies;
coordinating and integrating regulatory, benefits, operations and development functions;

49


demonstrating to customers acquisition will not result in adverse changes in coal quality, delivery schedules and other relevant deliverables;
managing and overcoming the unique characteristics of acquired entities or operations, such as the specific mining conditions at each of the acquired mines; retaining the personnel of acquired entities or operations and integrating the business cultures, operations, systems and clients of acquired entities or operations with our own;
consolidating corporate and administrative infrastructures and eliminating duplicative operations and
administrative functions; and
identifying the potential unknown liabilities associated with the Acquisitions.
In addition, overall integration will require substantial attention from our management, particularly in light of the geographically dispersed operations of acquired mines relative to our other mines and operations and the unique characteristics of the acquired assets. If our senior management team is required to devote considerable amounts of time to the integration process, it will decrease the time they will have to manage our business, develop new strategies and grow our business. If our senior management is not able to manage the integration process effectively, or if any significant business activities are interrupted as a result of the integration process, our business could suffer.
Furthermore, the anticipated benefits and synergies of acquisitions are based on assumptions and current expectations, with limited actual experience, and assume that we will successfully integrate and reallocate resources without unanticipated costs and that our efforts will not have unforeseen or unintended consequences. In addition, our ability to realize the benefits and synergies of the acquisitions could be adversely impacted to the extent that relationships with existing or potential customers, suppliers or the workforce is adversely affected as a consequence of the Acquisitions, as a result of further weakening of global economic conditions, or by practical or legal constraints on our ability to successfully integrate operations.
We cannot assure you that we will successfully or cost-effectively integrate acquired entities or operations into our operations in a timely manner, or at all, and we may not realize the anticipated benefits of the acquisition, including potential synergies or growth opportunities, to the extent or in the time frame anticipated. The failure to do so could have a material adverse effect on our financial condition, results of operations and business.
Our operations outside the United States may subject us to additional risks.
A significant portion of our assets, operations and revenues are located in Canada, and we will be subject to risks inherent in business operations outside of the United States. These risks include, without limitation:
impact of currency exchange rate fluctuations among the U.S. dollar, the Canadian dollar and foreign currencies relating to our export business, which may reduce the U.S. dollar value of the revenues, profits and cash flows we receive from non-U.S. markets or of our assets in non-U.S. countries or increase our supply costs, as measured in U.S. dollars in those markets;
exchange controls and other limits on our ability to repatriate earnings from other countries;
political or economic instability, social or labor unrest or changing macroeconomic conditions or other changes in political, economic or social conditions in the respective jurisdictions;
different regulatory structures (including creditor rights that may be different than in the United States) and unexpected changes in regulatory environments, including changes resulting in potentially adverse tax consequences or imposition of onerous trade restrictions, price controls, industry controls, safety controls, employee welfare schemes or other government controls;
increased financial accounting and reporting burdens and complexities resulting from the conversion and integration of the Canadian Subsidiaries’ Canadian dollar denominated, non-GAAP results of operations and statement of financial condition into GAAP-complaint financial statements that can be consolidated with our historical financial reports;
tax rates that may exceed those in the United States and earnings that may be subject to withholding requirements or that may be subject to tax in the United States prior to repatriation and incremental taxes upon repatriation;
difficulties and costs associated with complying with, and enforcement of remedies under, a wide variety of complex domestic and international laws, treaties and regulations;
distribution costs, disruptions in shipping or reduced availability of freight transportation; and
imposition of tariffs, quotas, trade barriers and other trade protection measures, in addition to import or export licensing requirements imposed by various foreign countries.

50


In addition, our management may be required to devote significant time and resources to adapting our systems, policies and procedures in order to successfully manage the integration and operation of foreign assets.
The Buckingham and San Juan Acquisitions may subject us to increased regulation and risks associated with underground mining.
The operations we acquired in the Buckingham Acquisition and the San Juan Acquisition primarily consist of underground mines. Underground mining operations are generally subject to more stringent safety and health standards than surface mining operations. More stringent state and federal mine safety laws and regulations have included increased sanctions for non-compliance. Future workplace accidents are likely to result in more stringent enforcement and possibly the passage of new laws and regulations. Our re-entry into underground mining operations will subject us to increased regulatory scrutiny and increased costs of regulatory compliance.

ITEM 1B
UNRESOLVED STAFF COMMENTS.
None
ITEM 2
PROPERTIES.
See “Coal - U.S. Segment - Properties,” “Coal - Canada Segment - Properties,” “Coal - WMLP Segment - Properties,” and “Power Segment” under Item 1 for information relating to our properties and reserves.
ITEM 3
LEGAL PROCEEDINGS.
We are subject, from time-to-time, to various proceedings, lawsuits, disputes, and claims (“Actions”) arising in the ordinary course of our business. Many of these Actions raise complex factual and legal issues and are subject to uncertainties. We cannot predict with assurance the outcome of Actions brought against us. Accordingly, adverse developments, settlements, or resolutions may occur and may result in a negative impact on income in the quarter of such development, settlement, or resolution. However, we do not believe that the outcome of any current Action would have a material adverse effect on our financial results.
ITEM 4
MINE SAFETY DISCLOSURE.
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 Act and Item 104 of Regulation S-K, are included as Exhibit 95.1 to this report on Form 10-K.

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PART II
ITEM 5
MARKET FOR REGISTRANT’S COMMON EQUITY, RELATED STOCKHOLDER MATTERS AND ISSUER PURCHASES OF EQUITY SECURITIES.
Market Information
Our common stock is listed and traded on the NASDAQ Global Market under the symbol WLB.
Holders
As of March 9, 2016, there were 1,066 holders of record of our common stock.
The following table shows the range of sales prices for our common stock for the past two years, as reported by the NASDAQ Global Market.
 
Sales Prices Common Stock
 
High
 
Low
2014
 
 
 
First Quarter
$
30.00

 
$
18.31

Second Quarter
37.15

 
25.79

Third Quarter
45.19

 
33.60

Fourth Quarter
40.99

 
27.49

2015
 
 
 
First Quarter
$
35.30

 
$
23.13

Second Quarter
30.92

 
20.46

Third Quarter
20.90

 
11.12

Fourth Quarter
16.14

 
4.17

Dividend Policy
Holders of our common stock are entitled to receive such dividends as our Board may declare from time to time from any surplus that we may have. We have not paid dividends on our common stock for some time and we do not anticipate paying any common stock dividends in the near future. In addition, the 8.75% Notes, the WCC Term Loan Facility and the WCC Revolving Credit Facility agreement restrict our ability to pay dividends on, or make other distributions in respect of, our capital stock unless we are able to meet certain ratio tests or other financial requirements. Should we be permitted to pay dividends pursuant to such instruments, the payment of such dividends will be dependent upon earnings, financial condition and other factors considered relevant by our Board and will be subject to limitations imposed under Delaware law.
Securities Authorized for Issuance Under Equity Compensation Plans
The information relating to our equity compensation plans required by Item 5 is incorporated by reference to such information set forth in Item 12 - Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters contained herein.
Issuer Purchase of Equity Securities
None.
Stock Performance Graph
The following performance graph compares the cumulative total stockholder return on our common stock for the five-year period December 31, 2010 through December 31, 2015 with (i) the cumulative total return over the same period of the NASDAQ Index, (ii) the cumulative total return over the same period of the NYSE MKT Composite Index, (iii) our former peer group, which consisted of Arch Coal, Alliance Resource Partners LP, Cloud Peak Energy, Foresight Energy LP, Peabody Energy, and Rhino Resource Partners LP and (iv) our current peer group index, which consists of Alliance Resource Partners LP, Arch Coal, Cloud Peak Energy, CONSOL Energy, and Peabody Energy. The graph assumes that: 
You invested $100 in Westmoreland Coal common stock and in each index at the closing price on December 31, 2010;
All dividends were reinvested;
Annual reweighting of the peer groups; and
You continued to hold your investment through December 31, 2015.

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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 stock.
 
At December 31,
Company/Market/Peer Group
2010
 
2011
 
2012
 
2013
 
2014
 
2015
Westmoreland Coal Company
$
100.00

 
$
106.78

 
$
78.22

 
$
161.56

 
$
278.14

 
$
49.25

NYSE MKT Composite Index
$
100.00

 
$
96.43

 
$
112.11

 
$
141.71

 
$
151.44

 
$
145.40

NASDAQ Financial Index
$
100.00

 
$
89.37

 
$
105.29

 
$
149.68

 
$
157.24

 
$
167.42

2015 Peer Group Index(2)
$
100.00

 
$
74.83

 
$
62.77

 
$
68.69

 
$
59.01

 
$
16.80

2014 Peer Group Index(3)
$
100.00

 
$
77.47

 
$
63.29

 
$
65.72

 
$
47.43

 
$
13.78

1.
Includes reinvestment of dividends
2.
2015 Peer Group: Alliance Resource Partners LP, Arch Coal, Cloud Peak Energy, CONSOL Energy, and Peabody Energy
3.
2014 Peer Group: Arch Coal, Alliance Resource Partners LP, Cloud Peak Energy, Foresight Energy LP, Peabody Energy, and Rhino Resource Partners LP

53


ITEM 6
SELECTED FINANCIAL DATA.
Westmoreland Coal Company and Subsidiaries
Five-Year Review
 
2015
 
2014(2)
 
2013
 
2012