10-K 1 wlb-123116_10k.htm 10-K Document

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, 2016
OR
 o 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
  ______________________________________________________________
wlblogo123116.jpg
(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 300, 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 o  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  o     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  o
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  o
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.  o



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
o
Accelerated filer
x
Non-accelerated filer
o  (Do not check if a smaller reporting company.)
Smaller reporting company
o
Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Act).    Yes  o    No  x
The aggregate market value of voting common stock held by non-affiliates as of June 30, 2016 was $154,439,980.
There were 18,572,233 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 24, 2017.
  ______________________________________________________________

DOCUMENTS INCORPORATED BY REFERENCE
Portions of the Definitive Proxy Statement on Schedule 14A to be filed within 120 days after December 31, 2016, in connection with the Company’s 2017 Annual Meeting of Stockholders scheduled to be held on May 16, 2017, are incorporated by reference into Part III of this Annual Report on Form 10-K (“Annual Report” or “Form 10-K”).



Explanatory Note

In this Annual Report for the year ended December 31, 2016, we are restating: (i) our consolidated balance sheet as of December 31, 2015 and our consolidated statements of operations and comprehensive income, and statements of cash flows for the years ended December 31, 2015 and December 31, 2014; and (ii) our unaudited quarterly financial information for 2016 and 2015. Restatement adjustments attributable to the years ended December 31, 2003 through 2013 are reflected as a net adjustment to retained earnings as of January 1, 2014.
Background and Effects of the Restatement
In connection with the preparation of the Company’s Annual Report and during the year-end audit, management reevaluated the Company’s January 1, 2003 adoption of FASB Statement No. 143, Asset Retirement Obligations (currently Accounting Standards Codification 410-20, Asset Retirement Obligations) in relation to the accounting for contractual reimbursements the Company will receive from certain customers upon the completion of final reclamation. The Company’s management has concluded that in these circumstances the Company’s reclamation receivables should have been recorded as mineral rights and depleted on a units-of-production basis, cash received on performance of final reclamation should have been recorded as revenue, and cost of sales should have been recognized to reflect accretion of the asset retirement obligation liability. We also corrected certain classification errors whereby costs incurred at the acquired Canadian mines were recorded as selling and administrative costs that under conformity with the parent company policy should have been reflected in cost of sales from the April 2014 acquisition date through December 31, 2016. Certain other immaterial prior period errors were also corrected as part of this restatement, which is further described in Note 2 - Restatement Of Previously Issued Consolidated Financial Statements to the consolidated financial statements. A summary quantification of the primary financial statement line items impacted by the restatement is as follows:
Financial Statement Impact
For the year ended December 31, 2015
 
For the year ended December 31, 2014
 
($ In millions)
Increase in revenue
8.5
 
15.0
Increase in cost of sales
30.4
 
30.3
Increase in depreciation, depletion, and amortization expense
8.8
 
8.6
Decrease in selling and administrative
(17.4)
 
(18.2)
Increase in operating loss
(13.4)
 
(5.7)
This restatement does not impact cash flows, liquidity, or debt covenant compliance, and increases Adjusted EBITDA due to the increase in revenue for the financial statements impacted by the restatement described above. Note that Adjusted EBITDA is a supplemental measure of financial performance that is not required by, or presented in accordance with, U.S. Generally Accepted Accounting Principles (“GAAP”) and is not intended to be a substitute for those reported in accordance with GAAP. A further explanation of Adjusted EBITDA, its use by management, and a reconciliation to the most directly comparable GAAP measure is included in Item 6 - Selected Financial Data. This change has no impact to the Company’s ability to receive the related contractual reclamation reimbursements.

Our management concluded that our internal controls over financial reporting are not effective due to a material weakness in the operating effectiveness of our controls over the application of the asset retirement obligation accounting literature in instances where the Company is reimbursed by its customers for final reclamation costs. We have also concluded that our disclosure controls were not effective solely because of this material weakness. Our discussion of disclosure controls and procedures included in Item 9A - Controls and Procedures and our report on internal control over financial reporting contained in this Annual Report discloses the impact of this material weakness on our chief executive officer’s and chief financial officer’s assessment of internal controls over financial reporting.
We have not amended our previously-filed Annual Reports on Form 10-K or Quarterly Reports on Form 10-Q for the periods affected by the restatement. The financial information that has been previously filed or otherwise reported for these periods is superseded by the information in this Form 10-K, and the financial statements and related financial information contained in such previously-filed reports should no longer be relied upon.

Additional information on the restatement can be found in this report in:
Part I - Cautionary Note Regarding Forward-Looking Statements
Part I, Item 1A - Risk Factors
Part II, Item 6 - Selected Financial Data

3


Part II, Item 7 - Management’s Discussion and Analysis of Financial Condition and Results of Operations
Part II, Item 8 - Financial Statements and Supplementary Data
Note 2 - Restatement Of Previously Issued Consolidated Financial Statements to the consolidated financial statements
Note 22 - Quarterly Financial Data (Unaudited) to the consolidated financial statements
Part II, Item 9A - Controls and Procedures

4


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
16

5


Cautionary Note Regarding Forward-Looking Statements

This Annual Report and materials we have filed or will file with the Securities and Exchange Commission (as well as information included in our other written or oral statements) contain or will contain certain statements that are forward-looking within the meaning of the Private Securities Litigation Reform Act of 1995. These statements are based on our expectations and assumptions at the time they are made and are not guarantees of future performance. Because forward looking statements relate to the future, they involve certain risks, uncertainties and assumptions that are difficult to predict. Actual outcomes and results may differ materially from those expressed in, or implied by, our forward-looking statements. Words such as “expects,” “intends,” “anticipates,” “believes,” “estimates,” “guides,” “provides guidance,” “provides outlook” and other similar expressions or future or conditional verbs such as “may,” “will,” “should,” “would,” “could,” and “might” are intended to identify such forward-looking statements. Readers of this Annual Report should not rely solely on the forward-looking statements and should consider all uncertainties and risks discussed in the “Risk Factors” section and throughout the Annual Report. The statements are only as of the date they are made, and the Company undertakes no obligation to update any forward-looking statement. Possible events or factors that could cause results or performance to differ materially from those expressed in our forward-looking statements include but are not limited to the following:
The effect of legal and administrative proceedings, settlements, investigations and claims, including any related to citations and orders issued by regulatory authorities, and the availability of related insurance coverage;
Existing and future legislation and regulation affecting both our coal mining operations and our customers’ coal usage, governmental policies and taxes, including those aimed at reducing emissions of elements such as mercury, sulfur dioxides, nitrogen oxides, particulate matter or greenhouse gases;
The effect of the Environmental Protection Agency’s and Canadian and provincial governments’ inquiries and regulations on the operations of the power plants to which we provide coal;
Alberta’s Climate Leadership Plan to phase out coal-fired electricity generation by 2030;
Our ability to manage the San Juan Entities (as defined in this Annual Report);
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;
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;
The ability or inability of our hedging arrangement with respect to our Roanoke Valley Power Facility (“ROVA”) to generate 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, including how power prices affect our customers’ decision to run their plants;
Seasonal variations and inclement weather may cause fluctuations in our operating results, profitability, cash flow and working capital needs related to our operating segments;
The availability and costs of key supplies or commodities, such as diesel fuel, steel and explosives;
Potential title defects or loss of leasehold interests in our properties, which could result in unanticipated costs or an inability to mine the properties;
Other factors that are described under the heading “Risk Factors” found in our reports filed with the Securities and Exchange Commission, including our Annual Reports on Form 10-K and our Quarterly Reports on Form 10-Q.
Unless otherwise specified, the forward-looking statements in this report speak as of the filing date of this report. Factors or events that could cause our actual results to differ may emerge from time-to-time, and it is not possible for us to predict all of them. We undertake no obligation to publicly update any forward-looking statements, whether because of new information, future developments or otherwise, except as may be required by law.

6


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
We produce and sell thermal coal primarily to investment grade utility customers under long-term, cost-protected contracts. Our focus is primarily on mine locations which allow us to employ dragline surface mining methods and take advantage of close customer proximity through mine-mouth power plants and strategically located rail transportation. At December 31, 2016, our U.S. coal operations were located in Montana, Wyoming, North Dakota, Texas, New Mexico and Ohio, and our Canadian coal operations were located in Alberta and Saskatchewan. We sold 54.7 million tons of coal in 2016.
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, Colorado in 1995 and relocated the headquarters to Englewood, Colorado in November 2011.
Today, Westmoreland Coal Company is an energy company employing approximately 3,200 employees. We conduct our operations through our subsidiaries and our principal sources of cash are distributions from our operating subsidiaries. See Exhibit 21.1 - Subsidiaries of the Registrant for a list of our subsidiaries. At December 31, 2016, our operations included 13 wholly-owned coal mines in the U.S. and Canada, a charcoal 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, at December 31, 2016, 93.9% of the total equity interest in, Westmoreland Resource Partners, LP (“WMLP”), which is a publicly traded limited partnership that owns and operates four mining complexes in Ohio and one mine in Wyoming. The following map shows our operations as of the date of this filing:
wlbmap123116.jpg

7


San Juan Acquisition
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 $121.0 million after customary 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.
Segment Information
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 Heritage and Corporate. 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., through which we have elected to retain some of our operating risks.
Due to the Kemmerer Drop (see Note 3 - Acquisitions to the consolidated financial statements for details), segment results for all periods presented in the financial statements contained in this Annual Report reflect Kemmerer as part of the Coal - WMLP segment and not part of the Coal - U.S. segment.
For each of our segments, Note 21 - Business Segment Information to the consolidated financial statements gives information regarding revenue, operating income and total assets.
Coal Segments
General
Each of our segments focuses 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. Eleven of our thirteen 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 several years up to 40 years. Our current coal sales contracts have a weighted average remaining term of approximately six years. See our segment financial statements at Note 21 - Business Segment Information to the consolidated financial statements.
Properties
Our proven and probable coal reserves are those we believe can be economically and legally extracted or produced at the time of the filing of this Annual Report. In determining whether our proven and probable coal reserves meet this economic and legal standard, we take into account, among other things, our potential ability or inability to obtain mining permits, the possible necessity of revising mining plans, changes in future cash flows caused by changes in estimated future costs, changes in mining permits, variations in quantity and quality of coal, and varying levels of demand and their effects on selling prices. The following table provides coal reserve quantities by segment from mines we own or control:
 
Coal - U.S.
 
Coal - Canada
 
Coal - WMLP(2)
 
Total
 
(In thousands of tons)
Coal reserves(1):
 
 
 
 
 
 
 
     Proven
355,333

 
372,679

 
118,785

 
846,797

     Probable
5,905

 
19,058

 
16,442

 
41,405

Total proven and probable reserves(3)
361,238

 
391,737

 
135,227

 
888,202

Permitted reserves
192,577

 
340,045

 
58,614

 
591,236

Current year production
22,406

 
22,862

 
7,088

 
52,356

____________________
(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:


8


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 closely 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 reserves for WMLP, of which we are the general partner and owner of 93.9% of the total outstanding equity interests (at December 31, 2016).

(3)
Reserve engineering is a process of estimating underground accumulations of coal that cannot be measured in an exact way. The accuracy of any reserve estimate depends on the quality of available data, the interpretation of such data and price and cost assumptions made by our reserve engineers. In addition, the results of mining, testing and production activities may justify revision of estimates that were made previously. If significant, such revisions would change the schedule of any further production and development of reserves. Accordingly, reserve estimates may differ from the quantities of coal that are ultimately recovered.
Substantially all of our properties and assets in the Coal - U.S. and Coal - Canada segments are encumbered by liens securing our and our subsidiaries’ outstanding indebtedness. See Note 10 - Debt And Lines Of Credit to the consolidated financial statements for explanation of defined debt terms below and additional encumbrance details. The holders of the 8.75% Notes and the lenders under the Term Loan 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, sales contracts, certain assets subject to existing liens and the San Juan Entities’ assets). The San Juan Entities’ assets are encumbered only by the San Juan Loan. Borrowings under the Revolver are secured by first priority liens on our and our wholly owned subsidiaries accounts receivable, inventory and certain other specified assets, other than the San Juan Entities’ assets. WMLP assets are encumbered by the WMLP Term Loan and WMLP Revolver. The WMLP assets secure the indebtedness of WMLP and its subsidiaries and are not part of the collateral with respect to the 8.75% Notes, the Term Loan, the San Juan Loan or the Revolver.

9


The following tables provide information about mines in our Coal - U.S., Coal - Canada, and Coal - WMLP segments as of December 31, 2016 (all tons data presented in thousands):

Coal - U.S. Mines
Colstrip
Absaloka
Savage
San Juan
Jewett(1)
Beulah
Buckingham
Previously owned by
Entech, Inc., a subsidiary of Montana Power, purchased 2001
Washington Group International, Inc. as contract operator, ended contract in 2007
Knife River Corporation, a subsidiary of MDU Resources Group, Inc., purchased 2001
San Juan Coal Company, LLC, a subsidiary of BHP Billiton, purchased 2016
Entech, Inc., a subsidiary of Montana Power, purchased 2001
Knife River Corporation, a subsidiary of MDU Resources Group, Inc., purchased 2001
Clay & Bryan Graham, purchased 2015
Currently owned by
Western Energy Company
Westmoreland Resources Inc.
Westmoreland Savage Corporation
San Juan Coal Company
Texas Westmoreland Coal Co.
Dakota Westmoreland Corporation
Buckingham Coal Company, LLC
County, State
Rosebud & Treasure, Montana
Big Horn, Montana
Richland, Montana
San Juan, New Mexico
Leon & Freestone & Limestone, Texas
McLean & Oliver, North Dakota
Lake, Ohio
Proven reserves
250,141
31,926
3,959
48,506
5,502
15,299
Probable reserves
4,343
1,562
Total reserves
250,141
31,926
3,959
52,849
5,502
16,861
Permitted reserves
85,453
31,926
3,959
52,849
1,529
16,861
2016 tons produced
8,798
4,135
309
3,904
3,665
884
711
Production capacity
13,300
7,500
400
4,500
7,000
500
750
2016 tons sold
8,812
4,157
309
5,417
3,690
948
729
2015 tons sold
9,626
5,844
271
 N/A
3,357
2,136
1,246
2014 tons sold
9,018
6,557
332
 N/A
5,255
2,731
 N/A
Estimated mine life with current plan
2024
2021
2028
2022
N/A
2019
2040
Lessor(2)
Fed Gov, State of MT, Great Northern Properties
Crow Tribe, Private parties
Fed Gov, Private parties
Fed Gov, State of NM
Private parties
Private parties, State of ND, Fed Gov
BCC ownership, AEP, Private parties, State of OH
Lease term
Varies
Through exhaustion
Varies
Varies
Varies
Varies
Varies
Coal seam
Rosebud
Rosebud-McKay
Pust
Fruitland No. 8
Wilcox Group
Schoolhouse, Beulah-Zap
Middle Kittanning
Coal type
Sub-bituminous
Sub-bituminous
Lignite
Sub-bituminous
Lignite
Lignite
Bituminous
Approx. heat content in 2016 (BTU/lb.)
8,417
8,516
6,397
10,176
6,821
6,977
11,959
Approx. sulfur content in 2016 (%)
0.68
0.62
0.46
0.77
1.07
0.61
2.23
Major customers(2)
Colstrip 1&2, Colstrip 3&4
Xcel Energy, Western Fuels Assoc.
Montana Dakota Utilities, Sidney Sugars
Public Service of New Mexico
NRG Texas Power LLC
Montana Dakota Utilities
AEP, Glatfelter
Delivery method
Truck, rail, conveyor belt
Truck, rail
Truck
Truck, conveyor belt
Conveyor belt
Rail
Truck, rail
Machinery
4 draglines, load-out facility
1 dragline, load-out facility
1 dragline
Longwall
4 draglines (customer owned), shovel
1 dragline, load-out facility
Prep plant, rail & truck load-out facility, 6 continuous miners
Gross Property, Plant & Equipment (in millions)
$270.7
$160.0
$11.4
$220.6
$162.7
$82.5
$42.3
Year complex opened
1968
1974
1958
1973
1985
1963
2007
Tons mined since inception
483,668
201,646
17,304
229,435
209,004
112,983
11,021
____________________
(1) The Jewett mine’s customer terminated the coal supply agreement on December 31, 2016.
(2) American Electric Power Company, Inc. (“AEP”).

10


Coal - Canada Mines
Paintearth
Genesee
Sheerness
Coal Valley
Poplar River
Estevan
Previously owned by
Sherritt International Corporation, purchased 2014
Currently owned by
Prairie Mines & Royalty ULC
City, Province
Forestburg, Alberta
Warburg, Alberta
Hanna, Alberta
Edson, Alberta
Coronach, Saskatchewan
Estevan, Saskatchewan
Proven reserves
18,943
151,560
25,092
6,788
48,722
121,574
Probable reserves
2,205
3,263
5,899
7,691
Total reserves
18,943
153,765
28,355
12,687
48,722
129,265
Permitted reserves
18,943
153,765
28,355
6,788
48,722
83,472
2016 tons produced
1,426
5,627
3,455
2,392
3,926
6,036
Production capacity
3,280
5,627
3,638
2,500
4,100
6,400
2016 tons sold
1,450
5,627
3,525
2,431
3,898
5,849
2015 tons sold
1,972
5,745
3,078
2,160
3,595
6,370
2014 tons sold
1,950
3,621
2,490
2,022
2,617
3,705
Estimated mine life with current plan
2029
2030
2025
2019
2029
2030
Lessor(3)
Crown, Freehold
 Crown, Freehold
 Crown
 Crown
 Crown, Freehold
 SaskPower, Crown, Freehold, Mancal, Private Owners
Lease term
 Varies
 Varies
 Varies
 Varies
 Varies
 Varies
Coal seam
Battle River, Paintearth
Ardley Coal Zone
Sunnynook, Sheerness
Val D'Or, Arbour, Mynheer
Willow Bunch
Souris, Roche Percee, Estevan
Coal type
Sub-bituminous
 Sub-bituminous
 Sub-bituminous
 Bituminous
 Lignite
 Lignite
Approx. heat content in 2016 (BTU/lb.)
7,341
8,278
7,013
10,800
5,758
6,818
Approx. sulfur content in 2016 (%)
0.45
0.23
0.50
0.30
 <0.99
0.59
Major customers(3)
ATCO Power
 Capital Power
 ATCO Power, TransAlta
 International & domestic
 SaskPower
 SaskPower
Delivery method
 Trucks
 Trucks
 Trucks
 Rail
 Rail
 Trucks
Machinery
2 draglines
2 draglines, shovels
2 draglines
4 draglines, 2 shovels
2 draglines
6 draglines
Gross Property, Plant & Equipment (in millions)
$24.8
$4.3
$42.9
$32.1
$50.1
$148.0
Year complex opened
1956
1988
1984
1978
1978
1973
Tons mined since inception
155,063
121,142
95,517
179,731
133,853
170,792
____________________
(3) Alberta Power (2000) Ltd. (“ATCO Power”); Saskatchewan Power Corporation (“SaskPower”).

11


Coal - WMLP Mines
Cadiz
Tuscarawas
Belmont
New Lexington
Noble(4)
Plainfield(4)
Muhlenberg(4)
Tusky(4)
Kemmerer
Previously owned by
The Ohio mines were previously owned by Oxford Resource Partners, LP which was purchased in December 2014.
Chevron Mining Inc., purchased 2012
Currently owned by
 The Ohio mines are currently owned by Oxford Mining Company, LLC except Muhlenberg which is owned by Oxford Mining Company - Kentucky, LLC.
Westmore- land Kemmerer, LLC
County, State
  Jefferson, Harrison, Ohio
  Stark, Tuscarawas, Ohio
  Belmont, Ohio
  Perry, Athens & Morgan, Ohio
  Noble & Guernsey, Ohio
 Muskingum, Guernsey & Coshocton, Ohio
 Muhlenberg & McLean, Kentucky
  Harrison & Tuscarawas, Ohio
 Lincoln, Wyoming
Proven reserves
4,743

4,567

7,910

3,804

229

3,622

1,227

18,965

73,718

Probable reserves
1,156


312

173



568

5,366

8,867

Total reserves
5,899

4,567

8,222

3,977

229

3,622

1,795

24,331

82,585

Permitted reserves
5,466

1,946

1,327

1,022


282

1,227

16,720

30,624

2016 tons produced
1,819

450

334

381





4,104

Production capacity
2,580

600

660

600

 N/A

 N/A

 N/A

 N/A

7,000

2016 tons sold
2,558

456

333

390





4,106

2015 tons sold
2,125

673

644

551

17




4,471

2014 tons sold
3,152

1,140

403

685

251




4,399

Estimated mine life with current plan
2022
2019
2019
2019
N/A
N/A
N/A
N/A
2026
Lessor(5)
 Private parties, Consol
 Private parties
 Private parties
 AEP, Private parties
 Private parties
 Private parties
 Private parties
 Private parties
Fed Gov, Private parties
Lease term
 Varies
 Varies
 Varies
 Varies
 Varies
 Varies
 Varies
 Varies
Varies
Coal seam
Pittsburgh, Redstone & Meigs Creek
Lower & Middle Kittanning, Upper Freeport, Mahoning, Brookville
Pittsburgh, Meigs Creek & Waynesburg
Lower & Middle Kittanning, Pittsburgh
Pittsburgh
Middle Kittanning
Tradewater & Carbondale Formations
Middle Kittanning & Upper Freeport
Adaville Series
Coal type
 Bituminous
 Bituminous
 Bituminous
 Bituminous
 Bituminous
 Bituminous
 Bituminous
 Bituminous
Sub-bituminous
Approx. heat content in 2016 (BTU/lb.)
11,420
11,768
11,742
11,550
11,286
11,711
11,424
12,900
10,019
Approx. sulfur content in 2016 (%)
2.60
3.80
4.50
3.80
5.30
4.40
3.50
2.10
0.71
Major customers(5)
 AEP & EKPC
 AEP
 AEP & EKPC
 AEP
N/A
N/A
N/A
N/A
PacifiCorp Energy, Inc.
Delivery method
Truck, rail, barge
Truck
Truck, barge
Truck, rail
N/A
N/A
N/A
N/A
Truck, rail, conveyor
Machinery
3 coal crushers with truck scales, rail load-out facility
Coal crusher with truck scale, blending facility, prep plant
Coal crusher, blending facility
Coal crusher with truck scale, rail load-out facility
N/A
N/A
N/A
N/A
Trucks, shovels, dozers
Gross Property, Plant & Equipment (in millions)
The Ohio mines' gross property, plant and equipment as of December 31, 2016 was $203.6 million.
$156.4
Year complex opened
2000
2003
1999
1993
2006
1990
2009
2003
1950
Tons mined since inception
452,647
192,984
16,172
175,059
191,730
107,489
107,489
15,148
192,841
____________________
(4) These mines were inactive during 2016.
(5) American Electric Power Company, Inc. (“AEP”); East Kentucky Power Cooperative (“EKPC”)




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Coal - U.S. Segment Properties
Our Coal - U.S. segment is composed of our wholly owned mines located in the United States excluding our mines in Ohio and Wyoming which are held in the Coal - WMLP segment. Mines in our Coal - U.S. segment control coal reserves and deposits through long-term leases. Montana, North Dakota, Texas and New Mexico each use a permitting process approved by the Office of Surface Mining. Mines in our Coal - U.S. segment 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 above. 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. We deliver coal via conveyor belt to our mine mouth customers and sell coal and lignite on a freight-on-board 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.
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% and 8.0%, for surface and underground mines, respectively, of the gross proceeds of coal mined and sold. Our private leases are generally long-term and have options for renewal. We believe that we have satisfied all lease conditions to retain the properties and keep the leases in place.
Coal - U.S. Segment Customers
In 2016, our Coal - U.S. segment derived approximately 83% of its revenues from coal sales to five customers: Public Service Company of New Mexico (28%); Colstrip Units 3&4 (22%); Colstrip Units 1&2 (12%), American Electric Power Company, Inc. (“AEP”) (11%); and NRG Texas Power LLC (10%). We sell the majority of our U.S. tons under contracts with a weighted average remaining supply obligation term of approximately four years.
Colstrip. The Colstrip mine has two long-term, cost-plus contracts with the adjacent Colstrip Station power generating facility.  In July 2016, we were notified by the owners of Colstrip Units 1 & 2 that our coal supply agreement will end three years early at the end of 2019. We currently sell approximately 2.3 million tons to Colstrip Units 1 & 2 annually. We expect approximately $10.7 million less operating income in 2020, 2021 and 2022, with minimal or no impact to operating income in 2017, 2018 or 2019. We do not expect there to be any impact to our contract related to Colstrip Units 3 & 4, which provides for approximately 6.3 million tons per year and currently expires at the end of 2019. The agreement related to Colstrip Units 3 & 4 also has provisions for specific returns on capital investments.
Absaloka. The Absaloka mine markets coal primarily in the open market and has several two- to eleven-year contracts with various parties. Burlington Northern Santa Fe (“BNSF”) 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 & 2 of the plant’s three generating units in 2026 and 2023, respectively.
Savage. The Savage mine supplies the Lewis & Clark 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 2017. Prices under the Lewis & Clark Station agreement are based on certain actual mine costs, commodity indices, and contain provisions for capital recovery.
San Juan. The San Juan mine was acquired on January 31, 2016 from BHP Billiton and supplies the San Juan Generating Station operated by Public Service Company of New Mexico. The customer is located within close proximity to the mine and coal deliveries are provided via off-road mine trucks and conveyor belt. The mine’s coal supply agreement expires in 2022 and reclamation is scheduled to be completed prior to 2035. As anticipated, at the end of 2017 the San Juan Generating Station will shut down two of their four units representing a 50% decrease in sales volume from the mine. Prices under the agreements are adjusted quarterly and are based on commodity indices for items such as diesel fuel. The reclamation agreement contains provisions for capital recovery.
Jewett. At our Jewett mine, our customer, NRG Texas Power (“NRG”), terminated our coal supply agreement two years early on December 31, 2016. We have now entered the reclamation phase of the mine life where NRG is responsible for the mine’s capital and reclamation expenditures. During 2016 and 2015, we supplied NRG with 3.7 million and 3.4 million tons of coal, respectively, which contributed an operating loss of $61.2 million and operating loss of $6.3 million for the same time periods, respectively. Westmoreland expects to maintain positive cash flow generation at the Jewett mine during the multi-year reclamation process.


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Beulah. The Beulah mine supplied the Coyote Electric Generating Plant via conveyor belt under an agreement that was not renewed in May 2016. We supplied approximately 2.5 million tons annually to the adjacent plant. During 2016 our operating loss from the Beulah mine was $0.7 million. During 2015, our operating income was $0.8 million. The mine currently supplies the Heskett Power Station by rail under an agreement that expires in 2021. Prices under this agreement are based upon certain actual mine costs and certain inflation/commodity indices.
Buckingham. The Buckingham mine conducts underground room and pillar mining operations in Ohio and has a preparation plant in Corning, Ohio. The mine is strategically located near WMLP’s New Lexington complex, which has access to the Norfolk Southern rail system and a preparation plant strategically located for efficient rail and river transportation of our coal. The Buckingham mine supplies coal to AEP under a five-year coal supply agreement ending in 2019 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 use substitute tonnage supplied through a contract with WMLP.
Coal - Canada Segment Properties
In 2015 we conducted our Canadian coal operations through Coal Valley Resources Inc. and Prairie Mines & Royalty ULC. On January 1, 2016 these two entities were amalgamated with the resulting entity continuing under the name Prairie Mines & Royalty ULC.
The majority of our Canadian coal production is sold to Canadian utilities for electricity production. All of our mines in Canada are surface mines. Five of our mines are mine-mouth where our mine is adjacent to the customer’s plant. Our Canadian mines are permitted in accordance with the legislation in effect in the Alberta and Saskatchewan 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. Coal reserves and leases in Canada are generally under the jurisdiction of provincial governments. We gain access to the Canadian coal reserves through provincial Crown coal leases, freehold ownership or third party leases or subleases. We believe that we have satisfied all lease conditions in order to retain these properties and keep the leases in place.
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 in Canadian dollars, which is roughly equivalent to $0.41 per ton in U.S. dollars. 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 in Canadian dollars per nominal section. The other is a freehold coal production tax, payable quarterly, of 7% on the mine mouth value of coal.
Coal - Canada Segment Customers
In 2016 our Coal - Canada segment derived approximately 86% of its revenues from coal sales to three customers: SaskPower (42%), the country of Japan (29%) and ATCO Power (15%). We sell the majority of our Canadian tons under contracts with a weighted average remaining supply obligation term of approximately 8 years.
Paintearth. The Paintearth mine operates two active pits and supplies the three power generating units at the Battle River Generating Station which are owned and operated by ATCO Power. Our coal supply contract expires in 2022.
Genesee. The Genesee mine operates two active pits and supplies the three power generating units at the Genesee Generating Station which are owned and operated by Capital Power. Our coal supply contract is currently projected to expire at the end of the current mine life through 2055, but the current Climate Leadership Plan from the Alberta government could limit the contract to 2030.
Sheerness. The Sheerness mine operates two active pits and supplies the two power generating units at the Sheerness Generating Station which are owned by ATCO Power and TransAlta Corporation and operated by ATCO Power. Our coal supply contract expires in 2026.

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Coal Valley. 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 contracts are generally short-term, one year contracts.
Poplar River. The Poplar River mine operates two active pits and supplies the two power generating units at the Poplar River Generating Station which is owned and operated by Saskatchewan Power Corporation. Our coal supply contract expires in 2029. The Poplar River mine owns and operates the railway from the mine to the generating station.
Estevan. The Estevan mine operates four active pits and supplies the Boundary Dam Generating Station (4 Units) (“Boundary Dam”), the Shand Generating Station (1 Unit) (“Shand”), the activated carbon plant, and the char plant. SaskPower has constructed and commissioned a carbon dioxide capture and sequestration facility at Boundary Dam and a carbon capture test facility at Shand. This combined project is funded by the government of Saskatchewan with backing from the Canadian government and should mitigate the impact of Canadian greenhouse gas regulations on Boundary Dam. Our coal supply contract expires in 2024. The Estevan mine combines the Bienfait mine and the adjacent Boundary Dam mine.
Activated Carbon Plant. A 50/50 joint venture with Cabot Corporation, the plant was initially commissioned in June 2010. The 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 100,000 tons of lignite char per year using coal from the Estevan mine. The char is sold to manufacturers of barbecue briquettes in the U.S.
Coal - WMLP Segment Properties
WMLP is a 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 markets in the Midwest, Northeast and Rocky Mountain regions of the U.S. as WMLP operates one surface mine in Wyoming and four surface mining complexes in Ohio comprised of ten active mines.
The Ohio operations include a river terminal on the Ohio River, two washing facilities, two rail loadout facilities and a tipple facility. The mines are a combination of area, contour, auger and highwall mining methods using truck/shovel and truck/loader equipment along with large production bulldozers. WMLP owns and operates six augers throughout its mining complexes. WMLP also utilizes highwall miner systems. WMLP owns or leases most of the equipment utilized in its mining operations and employs preventive maintenance and rebuild programs to ensure that its equipment is well maintained. During 2016, WMLP leased or subleased to others approximately 24.3 million tons of the total tons owned or controlled by WMLP. We believe that we have satisfied all lease conditions in order to retain the properties and keep the leases in place.
Coal - WMLP Segment Customers
In 2016, WMLP derived approximately 77% of its revenues from coal sales to three customers: AEP (38%), Pacificorp Energy, Inc. (29%), and East Kentucky Power Cooperative (10%). We sell the majority of our WMLP tons under contracts with a weighted average remaining supply obligation term of approximately two years.
Ohio. The Ohio operations supply AEP with contracts through 2018 and East Kentucky Power Cooperative with contracts through 2020 via rail, truck and barge.
Kemmerer. In August 2015, we contributed the Kemmerer mine from the Coal - U.S. segment to WMLP. The Kemmerer mine supplies the adjacent Naughton Power Station via conveyor belt under an agreement that expires in December 2021. Naughton’s Unit 3 is schedule to be shutdown at the end of 2017. The Kemmerer mine also supplies various industrial customers, including Tronox - Green River and Grainger, and Tata Chemicals North America Inc., through contracts extending to 2026. These industrial customers are supplied via Union Pacific rail and truck. Prices under the supply agreements are cost protected based on certain inflation/commodity indices.
Competition
The North American coal industry is intensely competitive. In addition to competition from other coal producers, we compete with producers of alternative fuels used for electrical power generation, such as nuclear energy, natural gas, hydropower, petroleum, solar and wind. Costs and other factors such as safety, environmental and regulatory considerations relating to alternative fuels affect the overall demand for coal as a fuel.

15


The majority of the mines in our Coal - U.S. and Coal - Canada segments, as well as our Kemmerer mine in the Coal - WMLP segment, focus on niche coal markets where we take advantage of long-term coal contracts with neighboring power plants. These mines give us a competitive advantage based on three factors:
we are among the most economic suppliers to our 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.
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.
The Coal - WMLP segment’s Ohio operations do not compete with producers of metallurgical coal or lignite. However, we do have limited competition from producers of Powder River Basin coal (sub-bituminous coal) in our target market area for bituminous coal. WMLP competes on the basis of delivered price, coal quality and reliability of supply. Its principal direct competitors are other coal producers, including (listed alphabetically) Alliance Resource Partners, L.P., Alpha Natural Resources, CONSOL, Foresight Energy, Hallador Energy Company, Murray Energy Corporation, Peabody Energy Corp., Rhino Resource Partners, L.P. and various other smaller, independent producers.
Washing Facilities
Depending on coal quality and customer requirements, some raw/crushed coal may be shipped directly from the mine to the customer. However, the quality of some raw coal does not allow direct shipment to the customer without putting the coal through a washing process that physically separates impurities from the coal. This processing upgrades the quality and heating value of the coal by generally removing ash, but it entails additional expense and results in some loss of coal. The Company owns and operates four washing facilities as follows:

Strasburg (Strasburg, Ohio): Throughput capacity of 200 tons of raw coal per hour and operated at a 50.0% utilization rate in 2016;

Conesville (Coshocton County, Ohio): Throughput capacity of 500 tons of raw coal per hour and operated at an 83.0% utilization rate in 2016 from January to April until it was idled the remainder of the year due to poor market conditions. This facility is adjacent to a customer’s power plant;

Buckingham (Corning, OH): Throughput capacity of 575 tons of raw coal per hour and operated at an 92.0% utilization rate in 2016;

Coal Valley (Edson, Alberta): Throughput capacity of 1,160 tons of raw coal per hour and operated at a 81.8% utilization rate in 2016.
Seasonality

Our coal business has historically experienced variability in its results due to the effect of the seasons. We are impacted by seasonality due to weather patterns and our customers’ annual maintenance outages which typically occur during the second quarter. In addition, our customers generally respond to seasonal variations in electricity demand based upon the number of heating degree days and cooling degree days. Due to stockpile management by our customers, our coal sales may not experience the same direct seasonal volatility; however, extended mild weather patterns can impact the demand for our coal. We experience the strongest net operating cash flows during the fourth quarter as our sales typically benefit from decreases in customers’ stockpiles due to high electricity demand, which generally occurs during the fourth quarter. Conversely, our net operating cash flows are typically weaker in the second quarter when our customers’ annual maintenance outages are scheduled. 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.

16


Power Segment

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 Term Loan. In 2016, the sale of power by ROVA to DNCP accounted for approximately 6% of our consolidated revenues.

Westmoreland Partners was party to a consolidated power purchase and operating agreement (the “Consolidated Agreement”) with Virginia Electric Power Company, which provided for the sale to DNCP and its affiliates of all of ROVA’s net electrical output and dependable capacity. On December 21, 2016, Westmoreland Partners entered into a Substitute Energy Purchase Agreement (“Amending Agreement”) that amended the Consolidated Agreement. Beginning March 1, 2017, the Amending Agreement adjusted the Substitute Energy and Capacity Purchase Price terms, replacing the latter with a fixed payment and other scheduled pricing through the end of the term. Accordingly, the Consolidated Agreement automatically
terminated and was superseded by the Amending Agreement. Westmoreland Partners is no longer obligated to operate ROVA in order to fulfill its contracted energy and capacity requirements. Under the Amending Agreement, Westmoreland Partners will continue to mitigate its cash losses from generation through the sale to DNCP of substitute power not produced by ROVA. 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.

As we are no longer required to operate ROVA under the Amending Agreement, we applied for and received approval to deactivate the plant from the PJM Interconnect. This deactivation took effect on March 1, 2017.

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.
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, Westmoreland Risk Management, Inc. (“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 U.S. 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 low 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.
Material Effects of Regulation
Safety
Following passage of The Mine Improvement and New Emergency Response Act of 2006, amending the Federal Mine Safety and Health Act of 1977, MSHA significantly increased the oversight, inspection and enforcement of safety and health standards and imposed safety and health standards on all aspects of mining operations. There has also been a dramatic increase in the dollar penalties assessed by MSHA for citations issued over the past several years. Most of the states in which we operate have inspection programs for mine safety and health. Collectively, federal, state and provincial safety and health regulations in the coal mining industry are comprehensive and pervasive systems for protection of employee health and safety. Safety is a core value of Westmoreland 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. Safety

17


performance at our mines was as follows:

2016
 
2015
 
Reportable Rate
 
Lost Time
Rate
 
Reportable Rate
 
Lost Time Rate
U.S. Surface Operations
1.34

 
0.70

 
1.36

 
0.71

U.S. National Surface Average
1.44

 
0.96

 
1.62

 
1.09

Percentage
93
%
 
73
%
 
84
%
 
65
%
 
 
 
 
 
 
 
 
U.S. Underground Operations
3.23

 
2.09

 
2.31

 

U.S. National Underground Average
4.95

 
3.56

 
4.70

 
3.30

Percentage
65
%
 
59
%
 
49
%
 
%
 
 
 
 
 
 
 
 
Canadian Operations
2.82

 
0.89

 
3.99

 
0.64

Regulations
We are subject to extensive regulation with respect to environmental and other matters by federal, state, provincial and local authorities in both the U.S. and Canada. Regulations to which we are subject include, but are not limited to, the following:
U.S. Federal Regulations
 
Canadian Provincial Regulations
Surface Mining Control & Reclamation Act of 1977
 
Alberta
Clean Air Act
 
Responsible Energy Development Act
Clean Water Act
 
Mines and Minerals Act
Endangered Species Act
 
Coal Conservation Act
Resource Conservation and Recovery Act
 
Environmental Protection and Enhancement Act
Comprehensive Environmental Response, Compensation and Liability Act
 
Public Lands Act
Emergency Planning and Community Right to Know Act
 
Water Act
Toxic Substances Control Act
 
 
Migratory Bird Treaty Act
 
Saskatchewan
 
 
The Crown Minerals Act
Canadian Federal Regulations
 
The Ecological Reserves Act
Fisheries Act
 
The Environmental Assessment Act
Canadian Environmental Assessment Act, 2012
 
The Environmental Management and Protection Act, 2010
Canadian Environmental Protection Act, 1999
 
The Provincial Lands Act
Species at Risk Act
 
Wildlife Act, 1998
Migratory Birds Convention Act, 1994
 
Various other climate change laws and initiatives
The U.S. Environmental Protection Agency (“EPA”) and/or other authorized federal or state agencies administer and enforce these U.S. regulations. We are also subject to extensive regulation regarding safety and health matters pursuant to the United States Mine Safety and Health Act of 1977, which is enforced by the U.S. Mine Safety and Health Administration (“MSHA”). Non-compliance with federal, tribal, 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.
U.S. Regulation
The following are summaries of certain U.S. federal regulations to which we are subject and their effects on us:
Surface Mining Control and Reclamation Act (“SMCRA”). SMCRA establishes minimum national operational, reclamation and closure standards for all surface coal mines. SMCRA requires that comprehensive environmental protection and reclamation standards be met during the course of and following completion of coal mining activities. Permits for all coal mining operations must be obtained from the Federal Office of Surface Mining Reclamation and Enforcement (“OSM”), or, where state regulatory agencies have adopted federally approved state programs under SMCRA, the appropriate state regulatory authority. States that operate federally approved state programs may impose standards that are more stringent than the requirements of SMCRA and OSM’s regulations and, in many instances, have done so. Permitting under SMCRA has generally become more difficult in recent years, which adversely affects the cost and availability of coal purchased by ROVA, especially

18


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. In January 2016, the Federal Bureau of Land Management announced a moratorium on new coal leases on federal lands. The moratorium does not affect existing leases. It is our policy to comply in all material respects with the requirements of the SMCRA and the state and tribal laws and regulations governing mine reclamation. We do not expect the moratorium to materially affect our operations based on current mine plans.
In December 2016, the OSM published the final Stream Protection Rule to reduce the environmental impact of surface coal mining operations.  The rule included the expansion of baseline data requirements and post-mining restoration requirements.  Under the Congressional Review Act, Congress approved H.J. Res. 38, disapproving the Stream Protection Rule.  President Trump signed H.J. Res. 38 on February 16, 2017.  The regulations in effect are those that were in place on January 18, 2017.  OSM is in the process of developing a final rule for publication in the Federal Register to amend all the regulations altered by the Stream Protection Rule back to the form in which those regulations existed on January 18, 2017.
Clean Air Act and Related Regulations. The U.S. Clean Air Act (“CAA”), and comparable state laws that regulate air emissions affect coal mining operations both directly and indirectly. Direct impacts on coal mining and processing operations include Clean Air Act permitting requirements and emission control requirements relating to air pollutants, including particulate matter, which may include controlling fugitive dust. The Clean Air Act indirectly affects coal mining operations by extensively regulating the emissions of particulate matter, sulfur dioxide, nitrogen oxides, mercury and other compounds emitted by coal-fired power plants. 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 greenhouse gases (“GHG”). The air emissions programs, regulatory initiatives and standards that may affect our operations, directly or indirectly, include, but are not limited to, the following:
Greenhouse Gas Emissions Standards. In August of 2015, the EPA finalized standards for greenhouse gases for new and modified electric generating units (“EGUs”) referred to as “new source performance standards” (“NSPS”). The final NSPS for coal-fired EGUs is set at 1,400 pounds of CO2 / megawatt hour on an average annual basis which would, with few possible exceptions, require the installation of partial carbon capture and sequestration at new or modified coal-fired EGUs. Under the CAA, new source performance standards like the GHG NSPS have binding effect from the date of the proposal, which in this case was January 8, 2014. Therefore, any new coal-fired EGU must comply with this standard, which is likely to be a major obstacle to the construction and development of any new coal-fired generation capacity. States and industry challenged the rule in the D.C. Circuit court, with oral arguments scheduled for April 17, 2017. Existing coal-fired generation, however, is also now subject to GHG performance standards that the EPA asserts will reduce GHG emissions from the power sector by 32% from 2005 levels by 2030. At the same time the EPA issued the GHG NSPS, the EPA finalized existing source standards for fossil-fuel fired power plants, which the EPA refers to as the Clean Power Plan. The final Clean Power Plan imposes stringent standards on existing fossil-fuel fired EGUs that reflect the EPA’s assessment of the “best system of emission reduction,” (“BSER”) including (1) average heat rate improvements of 6% for coal-fired power plants; (2) the re-dispatch of power based on an assumption that underutilized capacity at natural gas combined cycle facilities can be increased to an average of 75% of net summer capacity; and (3) the substitution of coal generation with renewable energy. These existing source standards are implemented by the states, which must meet individual GHG emission “goals” beginning in 2022 with phased reductions through 2030. Each state can choose either a rate-based or a mass-based goal that reflects the mix of natural gas and coal-fired generation in the state. The final goals have a greater impact on states with substantial coal-fired generation; Wyoming and North Dakota, for example, are faced with greater than 40% emission reductions from a 2012 baseline. Under the rule, the states had until September of 2016 to submit plans to the EPA to implement and enforce the state-specific BSER, although two-year extensions could have been requested by states in an initial submittal. States and industry groups challenged the rule in the U.S. Court of Appeals for the D.C. Circuit and requested a stay pending judicial review. Although the D.C. Circuit denied the stay request, in February of 2016, the U.S. Supreme Court issued a stay of the Clean Power Plan pending judicial review of the rule, including potential review by the Supreme Court. The stay delayed the implementation of the rule, including the state plan submittal dates. The D.C. Circuit reviewed the rule under an expedited briefing schedule, and an en banc panel heard oral arguments on September 27, 2016. If upheld by the courts, these rules have the potential to adversely affect our revenues and profitability, although it is difficult at this stage to determine the timing and extent of any such effects, or to determine the requirements of state plans resulting from these proposals that may ultimately be promulgated and require implementation. However, the Trump Administration has indicated that it intends to repeal the Clean Power Plan and it is uncertain whether it will be replaced. In June 2014, the U.S. Supreme Court in UARG v. 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

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program of the Clean Air Act. In 2016, the EPA proposed a rule to comply with the U.S. Supreme Court’s ruling by limiting the requirement to obtain permits controlling emissions of greenhouse gases to new large sources of other air pollutants, such as volatile organic compounds or nitrogen oxides, which also emit 100,000 tons per year or more of CO2 (or modifications of these sources that result in an emissions increase of 75,000 tons per year or more of CO2e). Therefore the permit provisions addressing GHG emissions from large industrial sources, such as fossil-fuel fired EGUs, remain in place.
Mercury Air Standards. In February 2012, the EPA published national emission standards under Section 112 of the CAA setting limits on hazardous air pollutant emissions from coal- and oil-fired EGUs, often referred to as the “Mercury Air Toxics Standards,” or “MATS Rule.” While the MATS Rule will generally require all coal- and oil-fired EGUs to reduce their hazardous air pollutant emissions, it is particularly problematic for any new coal-fired sources. The EPA agreed to reconsider the new source standards in response to requests by industry and published new source standards in April 2013. In June 2013, the EPA reopened for 60 days the public comment period on certain startup and shutdown provisions included in the November 2012 proposal. In June of 2015, the U.S. Supreme Court reversed the U.S. Court of Appeals for the D.C. Circuit and held that EPA had failed to properly consider costs when assessing whether to regulate fossil fuel-fired EGUs under the hazardous air pollutant provisions of the Clean Air Act, referring to the agency’s own estimate that the rule would cost power plants nearly $10 billion a year. The D.C. Circuit remanded the rule to EPA to conduct a cost assessment but without vacatur, allowing the rule to remain in effect while the EPA conducted the rulemaking. On December 1, 2015, the EPA published a proposed supplemental finding that regulation of EGUs is still “appropriate and necessary” in light of the costs to regulate hazardous air pollutant emissions from the source category. On April 14, 2016, the EPA issued a final rule confirming its “appropriate and necessary” finding to regulate air toxics, including mercury, from power plants after considering costs. The final rule was immediately challenged in the U.S. Court of Appeals for the D.C. Circuit in Murray Energy Corp. v. EPA and briefing is currently underway.
National Ambient Air Quality Standards (“NAAQS”) for Criteria Pollutants. The CAA requires the EPA to set standards, referred to as NAAQS, for six common air pollutants, including nitrogen dioxide and sulfur dioxide. Areas that are not in compliance (referred to as non-attainment areas) with these standards must take steps to reduce emissions levels. Meeting these limits may require reductions of nitrogen dioxide and sulfur dioxide emissions. Although our operations are not currently located in non-attainment areas, we could be required to incur significant costs to install additional emissions control equipment, or otherwise change our operations and future development if that were to change. On June 22, 2010, the EPA published a final rule that tightens the NAAQS for sulfur dioxide. On February 17, 2012, the EPA published final NAAQS for nitrogen dioxide. On January 15, 2013, the EPA published final NAAQS for particulate matter; the EPA lowered the annual standard for particles less than 2.5 micrometers in diameter but maintained the NAAQS for particles less than 10 micrometers in diameter. The EPA finalized designations for the sulfur dioxide NAAQS in 2013 for a handful of counties and delayed designations for the remainder of the country. The EPA finalized additional designations on June 30, 2016, with a supplement on November 29, 2016. For the remaining areas, the areas will be designated by the date determined by the Sulfur Data Requirements Rule. The EPA finalized nonattainment designations for nitrogen dioxide in January 2012. We do not know whether or to what extent these developments might affect our operations or our customers’ businesses. In 2008, the EPA finalized the current 8-hour ozone standard. In October 2015, the EPA issued a final rule lowering the ozone standard further. Several industry and business groups, five states, and Murray Energy Co. challenged the revised standard in the D.C. Circuit. Briefing has been completed and oral argument is scheduled for April 19, 2017. The Trump Administration also has indicated that it may revisit the standard. While it is likely that these and any future developments resulting in stricter NAAQS will to some degree adversely affect us, it is difficult at this stage to determine the timing and extent of such effects.
Clean Air Interstate Rule and Cross-State Air Pollution Rule (“CAIR”) and Cross-State Air Pollution Rule (“CSAPR”). The CAIR calls for power plants in 28 states and the District of Columbia to reduce emission levels of sulfur dioxide and nitrogen oxides pursuant to a cap-and-trade program similar to the system now in effect for acid rain. In 2008, the U.S. Court of Appeals for the District of Columbia Circuit found that the CAIR was fatally flawed, but ultimately agreed to allow it to remain in place pending the EPA’s development of a replacement rule because of concerns about potential disruptions. In June 2011, the EPA finalized the CSAPR as a replacement rule to the CAIR, which requires 28 states in the Midwest and eastern seaboard of the United States to reduce power plant emissions that cross state lines and contribute to ozone and/or fine particle pollution in other states. Under the CSAPR, the first phase of the nitrogen oxides and sulfur dioxide emissions reductions would commence in 2012 with further reduction effective in 2014. On December 15, 2011, the EPA finalized a supplemental rule-making to require Iowa, Michigan, Missouri, Oklahoma and Wisconsin to make summertime reductions to nitrogen oxide emissions under the CSAPR ozone-season control program. However, on December 30, 2011, the U.S. Court of Appeals for the District of Columbia Circuit stayed the implementation of CSAPR pending resolution of judicial

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challenges to the rules and ordered the EPA to continue enforcing the CAIR until the pending legal challenges have been resolved. In August 2012, the U.S. Court of Appeals vacated the CSAPR in a 2-to-1 decision and left the CAIR standards in place. In April 2014, the U.S. Supreme Court reversed the D.C. Circuit decision that vacated the CSAPR and remanded the cases for further proceedings consistent with the Court’s opinion, which acknowledged the possibility that under certain circumstances some states may have a basis to bring a particularized, as-applied challenge to the rule. The EPA filed a motion with the D.C. Circuit to lift its stay of the CSAPR and to toll for three years all deadlines that had not already passed as of the date the stay was granted. The D.C. Circuit granted the EPA’s motion in October 2014, and scheduled oral argument on the remaining challenge to the CSAPR for March 2015. In November, 2014 the EPA issued a ministerial rule aligning the CSAPR implementation dates with the Court’s order, with phase 1 reductions began in January 2015, and more stringent phase 2 reductions in January 2017. In July 2015, the D.C. Circuit remanded to the EPA portions of the 2014 sulfur dioxide and ozone budgets on grounds the reductions were greater than necessary to reduce impacts on downwind states, but did not vacate any portion of the rule. The EPA has indicated that it will address these issues in future rulemakings, but that phase 1 reductions began in January 2015, with more stringent phase 2 reductions in January 2017 as necessary. In September 2016, the EPA finalized an update to CSAPR ozone season program that lowered the ozone season emission budgets for the affected states. The update aligned compliance with the July 2018 attainment date for the 2008 ozone NAAQS.
Other Programs. A number of other air-related programs may affect the demand for coal and, in some instances, coal mining directly. For example, the EPA has initiated a regional haze program designed to protect and improve visibility at and around national parks, national wilderness areas and international parks. The EPA’s new source review program under certain circumstances requires existing coal-fired power plants, when modifications to those plants significantly change emissions, to install the more stringent air emissions control equipment required of new plants, and concerns about potential failures to comply have resulted in a number of high-profile enforcement actions and settlements over the years resulting in some instances in settlements under which operators install expensive new emissions control equipment. The Acid Rain program under Title IV of the CAA continues to impose limits on overall sulfur dioxide and nitrogen oxide emissions from regulated EGUs. In June 2013, President Obama issued a Climate Action Plan, which included a focus on methane reductions from coal mines. In January 2015, the Administration issued its methane strategy, but it did not include requirements for coal mines. In 2014 the D.C. Circuit upheld 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 (“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 were at particular risk of changes in applicable environmental laws with respect to the Jewett mine, whose customer, the NRG Texas Power- Limestone Station, blended our lignite with compliance coal from Wyoming, but NRG terminated our coal supply agreement two years early on December 31, 2016. With the termination of this contract, sales of lignite have ended and the Jewett mine is commencing final reclamation activities. NRG will 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 (the “Corps”) jointly issued a final rule to clarify which waters and wetlands are subject to regulation under the CWA. The implementation of this rule was stayed nationwide in October 2015. Recent court decisions, pending court challenges, regulatory actions and proposed legislation have created uncertainty over CWA jurisdiction and permitting requirements that could either increase or decrease the cost and time spent on CWA compliance. In January 2017, the Corps issued general nationwide permits for specific activities that are similar in nature and that are determined to have minimal adverse environmental effects. The permits will become effective in March 2017. The Corps reinstated the use of Nationwide Permit 21 for surface coal mining activities. In the event the acreage limits under the permit are exceeded, we will have to obtain individual permits from the Corps which will increase the processing time for future permit applications.
Endangered Species Act. The Federal Endangered Species Act (“ESA”), and similar state laws protect species threatened with extinction. Protection of endangered and threatened species may cause us to modify mining plans or develop

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and implement species-specific protection and enhancement plans to avoid or minimize impacts to endangered species or their habitats. A number of species indigenous to the areas where we operate are protected under the ESA. Based on the species that have been identified and the current application of applicable laws and regulations, we do not believe that there are any species protected under the ESA or state laws that would materially and adversely affect our ability to mine coal from our properties.
Resource Conservation and Recovery Act. We may generate wastes, including “solid” wastes and “hazardous” wastes that are subject to the federal Resource Conservation and Recovery Act (“RCRA”), and comparable state statutes, although certain mining and mineral beneficiation wastes and certain wastes derived from the combustion of coal currently are exempt from regulation as hazardous wastes under RCRA. The EPA has limited the disposal options for certain wastes that are designated as hazardous wastes under RCRA. Furthermore, it is possible that certain wastes generated by our operations that currently are exempt from regulation as hazardous wastes may in the future be designated as hazardous wastes, and therefore be subject to more rigorous and costly management, disposal and clean-up requirements.
The EPA determined that coal combustion residuals (“CCR”) do not warrant regulation as hazardous wastes under RCRA in May 2000. Most state hazardous waste laws do not regulate CCR as hazardous wastes. The EPA also concluded that beneficial uses of CCR, other than for mine filling, pose no significant risk and no additional national regulations of such beneficial uses are needed. However, the EPA determined that national non-hazardous waste regulations under RCRA are warranted for certain wastes generated from coal combustion, such as coal ash, when the wastes are disposed of in surface impoundments or landfills or used as minefill. The EPA Administrator Gina McCarthy signed the final rule relating to the disposal of CCR from electric utilities on December 19, 2014 and submitted it to the Federal Register for publication. The final rule regulates CCR as solid waste under RCRA. The final rule establishes national minimum criteria for existing and new CCR landfills, surface impoundments and lateral expansions. The criteria include location restrictions, design and operating criteria, groundwater monitoring and corrective action, closure requirements and post-closure care and recordkeeping, notification and Internet posting requirements. The rule is largely silent on the reuse of coal ash. These changes in the management of CCR could increase both our and our customers’ operating costs and potentially reduce their ability to purchase coal. In addition, contamination caused by the past disposal of CCR, including coal ash, could lead to citizen suit enforcement against our customers under RCRA or other federal or state laws and potentially reduce the demand for coal.
Comprehensive Environmental Response, Compensation, and Liability Act. Under the Comprehensive Environmental Response, Compensation, and Liability Act (“CERCLA” or “Superfund”) and similar state laws, responsibility for the entire cost of cleanup of a contaminated site, as well as natural resource damages, can be imposed upon current or former site owners or operators, or upon any party who released one or more designated “hazardous substances” at the site, regardless of the lawfulness of the original activities that led to the contamination. CERCLA also authorizes the EPA and, in some cases, third parties to take actions in response to threats to public health or the environment and to seek to recover from the potentially responsible parties the costs of such action. In the course of our operations, we may have generated and may generate wastes that fall within CERCLA’s definition of hazardous substances. We may also be an owner or operator of facilities at which hazardous substances have been released by previous owners or operators. We may be responsible under CERCLA for all or part of the costs of cleaning up facilities at which such substances have been released and for natural resource damages. We have not, to our knowledge, been identified as a potentially responsible party under CERCLA, nor are we aware of any prior owners or operators of our properties that have been so identified with respect to their ownership or operation of those properties. We also must comply with reporting requirements under the Emergency Planning and Community Right-to-Know Act and the Toxic Substances Control Act.
 Climate Change Legislation and Regulations. Numerous proposals for federal and state legislation have been made relating to GHG emissions (including carbon dioxide) and such legislation could result in the creation of substantial additional costs in the form of taxes or required acquisition or trading of emission allowances. Many of the federal and state climate change legislative proposals use a “cap and trade” policy structure, in which GHG emissions from a broad cross-section of the economy would be subject to an overall cap. Under the proposals, the cap would become more stringent with the passage of time. The proposals establish mechanisms for GHG sources such as power plants to obtain “allowances” or permits to emit GHGs during the course of a year. The sources may use the allowances to cover their own emissions or sell them to other sources that do not hold enough emissions for their own operations. Some states, including California, and regional groups including a number of states in the northeastern and mid-Atlantic regions of the U.S that are participants in a program known as the Regional Greenhouse Gas Initiative (often referred to as “RGGI”), which is limited to fossil-fuel-burning power plants, have enacted and are currently operating programs that, in varying ways and degrees, regulate GHGs.
In addition, the EPA, acting under existing provisions of the Clean Air Act, has begun regulating emissions of GHG, including the enactment of GHG-related reporting and permitting rules as described above. In June of 2014, the U.S. Supreme Court overturned the EPA’s GHG permitting rules to the extent they required permits based solely on emissions of GHG; however, the EPA has proposed a rule to comply with the U.S. Supreme Court’s ruling by limiting the requirement to obtain permits controlling emissions of greenhouse gases to large sources of other air pollutants, such as volatile organic compounds

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or nitrogen oxides, which also emit 100,000 tons per year or more of CO2 (or modifications of these sources that result in an emissions increase of 75,000 tons per year or more of CO2e). Underground coal mines remain subject to the EPA’s GHG Reporting Program, which requires mines to submit annual GHG emission estimates to the EPA, but that program has not been extended to surface coal mines.
The impact of GHG-related legislation and regulations, including a “cap and trade” structure, on us will depend on a number of factors, including whether GHG sources in multiple sectors of the economy are regulated, the overall GHG emissions cap level, the degree to which GHG offsets are allowed, the allocation of emission allowances to specific sources and the indirect impact of carbon regulation on coal prices. We may not recover from our customers the costs related to compliance with regulatory requirements imposed on us due to limitations in our agreements.
Passage of additional state or federal laws or regulations regarding GHG emissions or other actions to limit carbon dioxide emissions could result in fuel switching from coal to other fuel sources by electricity generators and thereby reduce demand for our coal or indirectly the prices we receive in general. In addition, political and regulatory uncertainty over future emissions controls have been cited as major factors in decisions by power companies to postpone new coal-fired power plants. If these or similar measures, such as controls on methane emissions from coal mines, are ultimately imposed by federal or state governments or pursuant to international treaties, our operating costs or our revenues may be materially and adversely affected. In addition, alternative sources of power, including wind, solar, nuclear and natural gas could become more attractive than coal in order to reduce carbon emissions, which could result in a reduction in the demand for coal and, therefore, our revenues. Similarly, some of our customers, in particular smaller, older power plants, could be at risk of significant reduction in coal burn or closure as a result of imposed carbon costs. The imposition of a carbon tax or similar regulation could, in certain situations, lead to the shutdown of coal-fired power plants, which would materially and adversely affect our revenues.
Bonding Requirements. Federal and state laws require mine operators to assure, usually through the use of surety bonds, payment of certain long-term obligations, including the costs of mine closure and the costs of reclaiming the mined land. The costs of these bonds have fluctuated in recent years, and the market terms of surety bonds have generally become more favorable to us. Surety providers are requiring smaller percentages of collateral to secure a bond, which will require us to provide less cash to collateralize bonds to allow us to continue mining. These changes in the terms of the bonds have been accompanied, at times, by an increase in the number of companies willing to issue surety bonds. See Note 7 - Restricted Investments to the consolidated financial statements for the amount of surety bonds posted and cash collateral for reclamation purposes.
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 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 Saskatchewan (the two provinces where we do business), and the federal laws applicable therein to which we are subject and their potential effects on 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:

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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 has 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 U.S. bonding requirements mentioned above, the 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.

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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.
The Environmental Management and Protection Act, 2010. The Environmental Management and Protection Act, 2010 (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).

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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 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 offense 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 U.S., the direct and indirect costs of various GHG related regulations, existing and proposed in Canada, may adversely affect our business.
In 2016, the Alberta government took steps to implement some of its proposals under the previously announced Alberta Climate Leadership Plan (the “ACL Plan”). The ACL Plan proposed to phase out pollution from coal-fired electricity plants in Alberta by 2030. To that purpose, the Government reached agreements with the three owners of the six coal-fired generation power plant units previously scheduled to operate past 2030. These announced agreements provide for the shutting down of these six units by December 31, 2030. Three of these six units are at the Genesee Generating Station, which is fueled by our Genesee mine operations. Two of these six units are at the Sheerness Generating Station, which is fueled by our Sheerness mine operations. These events will adversely affect our potential business at those two mines post 2030.
The ACL Plan also proposed the implementation of a carbon levy on fuels that emit GHG. The Climate Leadership Act (the “CL Act”) passed in 2016 introduced a carbon levy on all fuels that emit GHG emissions when combusted. Starting January 1, 2017, the carbon levy rate is $20/tonne of carbon emission released by the fuel when combusted. The rate increases to $30/tonne effective January 1, 2018. As a result of the carbon levy, starting January 1, 2017, diesel fuel costs to operate our Alberta mines have increased at all sites except the Coal Valley mine (exempt from carbon levy due to coverage under SGE Regulation described below). Coal sales to power plants and export sales are exempt from the carbon levy. We have minimal Alberta coal sales that are not export sales or sales to power plant customers, on which starting January 1, 2017 we are required to collect and remit the carbon levy.
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

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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. The SGE Regulation is applicable to the Coal Valley mine and also the power plants that are our customers. The Alberta government has announced plans to replace the SGE Regulation for large GHG emitters effective January 1, 2018 with an output-based allocation approach. The Alberta government is still working on the details of such an approach and the transition to it.
In 2016 the Federal government announced that they will speed up plans to phase out Canadian coal-fired electricity by 2030. Subsequently, the Saskatchewan and Federal governments announced that they have reached an agreement in principle that will allow Saskatchewan to continue to use coal in a responsible manner beyond 2030 as long as equivalent emission reduction outcomes are achieved. This takes into accounts Saskatchewan’s entire generation capacity as well as their use of carbon capture and storage. We are unable to predict the impact of these events on our business and it is possible that they may have a material effect on our business, financial condition, results of operations and cash flows if coal use in Saskatchewan is reduced.
Also in 2016, the Federal government announced that they will require all Canadian jurisdictions to have a carbon pricing regime in place by 2018. This carbon pricing regime can be a direct price on carbon emissions or an adopted cap-and-trade system. Legislation related to this announcement has not yet been put forward.
Future federal legislation, including any related to their announced plans, 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, or require reduced output. Any failure to meet emission reduction compliance obligations may materially adversely affect our business and result in fines, penalties and the suspension of operations. 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. 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.
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) 922-6463 or by mail at Westmoreland Coal Company, 9540 South Maroon Circle, Suite 300, 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, but not limited to, those summarized below.
Risks Related to Restatement
The restatement of our previously issued financial statements contained in this Annual Report may lead to additional risks and uncertainties, including regulatory, shareholder or other actions, loss of investor confidence and negative impacts on our stock price.

Our Audit Committee, after considering the recommendation of management, concluded that our previously issued consolidated financial statements should be restated for the reasons described in the Explanatory Note to this Form 10-K and Note 2 - Restatement Of Previously Issued Consolidated Financial Statements to the consolidated financial statements and, accordingly, that such financial statements should no longer be relied upon. In this Annual Report for the year ended December 31, 2016, we are restating: (i) our consolidated balance sheet as of December 31, 2015 and our consolidated statements of operations and comprehensive income, and statements of cash flows for the years ended December 31, 2015 and December 31, 2014; and (ii) our unaudited quarterly financial information for 2016 and 2015. Restatement adjustments attributable to fiscal years 2003 through 2014 are reflected as a net adjustment to retained earnings as of January 1, 2014.
As a result of this restatement and associated non-reliance on previously issued financial information, we have become subject to a number of additional costs and risks, including unanticipated costs for accounting and legal fees in connection with or related to the restatement and the remediation of our ineffective disclosure controls and procedures and material weakness in internal control over financial reporting. Likewise, the attention of our management team has been diverted by these efforts. In addition, we could also be subject to additional shareholder, governmental, regulatory or other actions or demands in connection with the restatement or other matters. Any such proceedings will, regardless of the outcome, consume a significant amount of management’s time and attention and may result in additional legal, accounting, insurance and other costs. If we do not prevail in any such proceedings, we could be required to pay damages or settlement costs. In addition, the restatement and related matters could impair our reputation or could cause our customers, shareholders, or other counterparties to lose confidence in us. Any of these occurrences could have a material adverse effect on our business, results of operations, financial condition and stock price.
We have identified a material weakness in our internal controls that, if not properly corrected, could result in material misstatements in our financial statements.
In connection with the restatement of our financial statements for the years ended December 31, 2015 and 2014 and the unaudited quarterly financial data for all quarters within the years ended December 31, 2016 and 2015, our management identified a material weakness in our internal control over financial reporting as of February 24, 2017. A material weakness is a deficiency, or combination of deficiencies in internal controls over financial reporting that results in a reasonable possibility that a material misstatement of our annual or interim financial statements will not be prevented or detected on a timely basis. Further, management determined that control deficiencies existed with respect to certain aspects of our historical financial reporting and, accordingly, management has concluded that management’s reports related to the effectiveness of internal and disclosure controls may not have been correct. We did not maintain effective internal control over financial reporting as of December 31, 2015 or 2014 as is set forth in Item 9A - Controls and Procedures of the Company’s Annual Report.
The material weakness identified by management was due to the lack of operating effectiveness of our controls over the application of the asset retirement obligation accounting literature in instances where the company is reimbursed by its customers for final reclamation expenditures. As a result, reclamation receivables were recorded which should have been classified as an asset retirement cost and depleted on a units-of-production basis. The material weakness allowed errors to occur that were not detected in a timely manner therefore requiring a restatement of the financial statements discussed in the Explanatory Note to this Form 10-K and Note 2 - Restatement Of Previously Issued Consolidated Financial Statements to the consolidated financial statements. The errors do not impact cash flows or liquidity for any previously issued financial statements.
As a result of the material weakness determination, and effective as of December 31, 2016, our management discontinued the previously used accounting policy and oversight method for reclamation receivables and implemented an approach prescribed by GAAP. Management further assigned personnel with the appropriate level of asset retirement obligation and technical accounting experience to review the accounting for asset retirement obligations. Accordingly, management does not expect the material weakness associated with this accounting policy to recur. If the changes in accounting

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policy and oversight method do not remedy the control deficiencies and we are not able to otherwise remedy these control deficiencies in a timely manner, we may be unable to provide holders of our securities with the required financial information in a timely and reliable manner, either of which could subject us to litigation and regulatory enforcement actions.

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 had become increasingly stringent, as well as increased pressure from environmental activists, may reduce demand for our products. For example, a consortium of environmental activists is actively pushing to shut down one-third of the U.S. coal plants by 2020. They are taking particular interest in Colstrip Units 1 & 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 the 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. In July 2016, Colstrip owners entered into a settlement agreement with Sierra Club to dismiss the Clean Air Act violations in exchange for retirement of Units 1 and 2 no later than July 1, 2022. As a result of the settlement agreement, we expect to lose coal sales of approximately 2.3 million tons per year beginning the year of retirement. 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 abandoned plans to convert Unit 3 at Naughton to 100% natural gas fueling. Instead, the owner has stated that it intends to retire Naughton Unit 3 at the end of 2017. This retirement will result in the loss of coal sales at our Kemmerer mine. However, Rocky Mountain Power stated that it will continue to consider potential alternatives to allow continued operation of Unit 3 beyond 2017. In addition, price protections built into the contract that are in effect from 2017 to 2021 will partially offset the effects of lowered volume. 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 Corps issued a final rule to clarify which waters and wetlands are subject to regulation under the CWA. The implementation of this rule was stayed nationwide in October 2015. In January 2017, the Corps issued general nationwide permits for specific activities, including surface coal mining activities. Permitting challenges may increase if our activities do not qualify for nationwide permit coverage. A change in CWA jurisdiction and permitting requirements could increase or decrease our permitting and compliance costs.
The EPA has executed a final rule relating to the disposal of CCR from electric utilities. The changes to the management of CCR could increase our and our customers’ operating costs and reduce sales of coal.
In December 2016, the OSM published the final Stream Protection Rule to reduce the environmental impact of surface coal mining operations.  The rule included the expansion of baseline data requirements and post-mining restoration requirements.  Under the Congressional Review Act, Congress approved H.J. Res. 38, disapproving the Stream Protection Rule.  President Trump signed H.J. Res. 38 on February 16, 2017.  The regulations in effect are those that were in place on January 18, 2017.  OSM is in the process of developing a final rule for publication in the Federal Register to amend all the regulations altered by the Stream Protection Rule back to the form in which those regulations existed on January 18, 2017. If this rule is not amended, our permitting and compliance costs could increase.
In January 2016, the Federal Bureau of Land Management announced a moratorium on new coal leases on federal lands. The moratorium does not affect our existing federal leases. If the moratorium remains in force, it is unlikely to have a material impact on our ability to conduct future operations because we do not ordinarily bid on federal coal leases.
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

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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 Canadian mines’ 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 our Canadian mines. However, our Canadian operations involve large facilities, so the setting 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, 2016, we had a total outstanding indebtedness of approximately $1,147 million as detailed in Note 10 - Debt And Lines Of Credit to the consolidated financial statements. 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 Term Loan, the San Juan Loan, the Revolver or other debt or fail to comply with the financial and other restrictive covenants contained in the 8.75% Notes, the Term Loan, the San Juan Loan, the Revolver 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 Term Loan, the San Juan Loan and the Revolver;
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 Term Loan, San Juan Loan and the Revolver;
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 Term Loan, the San Juan Loan and the Revolver. In conjunction with our acquisition of the GP, WMLP entered into the WMLP Term Loan to refinance WMLP’s indebtedness. Although the WMLP Term Loan is 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 is obligors under the WMLP Term Loan and the 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, financial covenants and cross-default provisions. 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.

Access to our Revolver is dependent upon our compliance with certain financial ratio covenants. This includes a minimum fixed charge coverage ratio of 0.90 in certain quarters for both the US and Canada components of the Restricted Group and 1.10 for the Restricted Group on a consolidated basis. The fixed charge coverage ratio is generally calculated based on Adjusted EBITDA (as defined in the debt agreement) divided by scheduled principal and interest payments for the most recently completed four quarters. At December 31, 2016 the US, Canada and consolidated Restricted Group fixed charge ratios were approximately 1.5, 1.1 and 1.25, respectively. Additionally, the San Juan Loan requires a minimum debt service coverage ratio of 1.05 The debt service coverage ratio is generally calculated as cash generated by the borrower and its subsidiaries divided by required debt service payments, including scheduled principal and interest payments. At December 31, 2016 the debt service coverage ratio was 1.13. Breaches of the Revolver financial covenants would cause a cross-default of the 8.75% Notes, the Term Loan and the San Juan Loan. Breaches of the San Juan Loan covenant would cause a cross-default of the 8.75% Notes and the Term Loan. Based on our quarterly projections, including the impact of lost or diminished coal sales at certain of our mines, we anticipate that we will maintain compliance with the financial covenants and have sufficient liquidity to meet our obligations as they become due within one year after the date of the filing of our Annual Report.
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, to make scheduled payments on our indebtedness and comply with our financial covenants 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 Term Loan, the San Juan Loan or our other debt or comply with the financial covenants associated with the Revolver and the San Juan Loan.

If our cash flow and capital resources are insufficient to meet our debt service obligations, to fund our other liquidity needs, or comply with our financial covenants, we may need to renegotiate our debt covenants, 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 renegotiate our covenants, 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 covenants, 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 Term Loan, the San Juan Loan and the Revolver could declare all outstanding principal and interest to be due and payable, the lenders under the Revolver could terminate their commitments to loan money to us, the holders of the 8.75% Notes and the lenders under the Term Loan, the San Juan Loan and the Revolver 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 amendments to our debt facilities 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.

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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 2016, our Coal - U.S. segment derived approximately 83% of its total revenues from coal sales to five power plants: Public Service Company of New Mexico (28%); Colstrip Units 3&4 (22%); Colstrip Units 1&2 (12%), AEP (11%); and NRG Texas Power LLC (10%). Our Coal - Canada segment derived approximately 86% of its total revenues from coal sales to three customers: SaskPower (42%), the country of Japan (29%) and ATCO Power (15%). WMLP derived approximately 77% of its total coal revenues from sales to three customers: American Electric Power Company, Inc. (38%), Pacificorp Energy, Inc. (29%) and East Kentucky Power Cooperative (10%). 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. Sixteen of our 18 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.
Certain of our long-term contracts are set to expire in the next several years. Our contracts with the Sherburne County Station (i.e., Xcel Energy) are three-year rolling contracts, with one-third of the tonnage expiring on an annual basis. As of December 31, 2016, we have contracted tons through 2018. Our contract with Coyote Station, located adjacent to our Beulah mine and averaging approximately 2.5 million tons of coal sold per year, expired in May 2016. Our contract with NRG at Jewett expired two years early on December 31, 2016 (during 2016 we supplied NRG with 3.7 million tons), and our contract with Colstrip Units 1 & 2 will be terminated three years early in 2019 which equates to approximately 2.3 million tons annually and $10.7 million in operating income annually. 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 mines we acquired in Canada 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, 2016, 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.
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 Amending Agreement with respect to our ROVA facility permits Westmoreland Partners to
mitigate its cash losses through the sale to DNCP of fixed-price purchased power. 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.
Our ability to collect payments from our customers could be impaired if their creditworthiness deteriorates.

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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.
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.
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. See Note 12 - Pension And Other Saving Plans to the consolidated financial statements for the projected benefit obligation under our defined benefit pension plans at year end and the fair value of plan assets. This note also details our contributions to these pension plans and accrued expenses related thereto in the current year. 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, black lung 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. GAAP. We estimate the present value of our postretirement medical, black lung and workers’ compensation benefit obligations to be $323.6 million, $17.6 million and $5.0 million, respectively, at December 31, 2016. Our Canadian operations 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. See Note 11 - Postretirement Medical Benefits to the consolidated financial statements for our contributions to these funds which could increase as a result of a shrinking contribution base due to 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 (“IUOE”). 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, 2016, 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 was 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.

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Our Canadian operations 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 and the percentage of coal ultimately recoverable;
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 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.
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. Inaccuracies in our reserve estimates could result in decreased profitability from lower than expected revenues or higher than expected costs.
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

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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.
See Note 13 - Asset Retirement Obligations to the consolidated financial statements for our gross reclamation estimate and mine-closing liabilities which are based upon projected mine lives, current mine plans, permit requirements and our experience. The note details reclamation deposits held by us and received from customers to provide for these obligations. The note also shows our estimated obligation for final reclamation that was not the contractual responsibility of others or covered by offsetting reclamation deposits and how much we must recover from revenues to fund this deficit. 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 and San Juan mines, 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 and Coal Valley mines, 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, 2016, 11 of our 29 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, 2016, the average age of Westmoreland’s dragline fleet was 34 years. As our 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,

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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 at levels we believe are appropriate and consistent with industry practice for some, but not all, of the potential risks and liabilities associated with our business; we are not fully insured against all risks. 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. 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 at WMLP 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.
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.

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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 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;
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. WMLP distributions of cash largely ceased to us and are not expected to resume at significant levels for the foreseeable future.

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The exchange of our Common Units in WMLP for Series B Units of WMLP will negatively affect our cash flow.
Since acquiring the GP and a significant limited partner interest in WMLP, we have received quarterly cash distributions from WMLP. Our exchanging of 4,512,500 Common Units for the same amount of Series B Units, which are not entitled to receive such distributions, will cause us to forfeit cash distributions associated with the Common Units, resulting in a decrease of approximately $601,516 in quarterly cash flow based on WMLP’s current quarterly distribution amount of $0.1333 per Common Unit. This negative impact to our cash flow could have a negative impact on our business and results of operations as a whole.

The conversion of Series B Units of WMLP back to Common Units in WMLP is anticipated to result in additional tax losses being allocated to us that may occur over multiple years.
The Series B Units are convertible on a one-for-one basis into Common Units on the day after the record date for a cash distribution on the Common Units in which WMLP is unable to make such a distribution without exceeding its restricted payment basket under the WMLP Term Loan Facility and the WMLP Revolving Credit Facility. The Series B Units will also convert automatically upon a change of control or a dissolution or liquidation of WMLP. Upon the conversion of Series B Units to Common Units, allocations of income, gain, loss or deduction will be made to cause the Common Units received to be fungible with the Common Units held by others. It is anticipated that this will result in an allocation of losses or deductions to WMLP. While the conversion of a Series B Unit occurs at a particular time, the allocations may occur over multiple years. If the allocations do not occur in the same year as the conversion, we will have fewer losses or deductions in that year than otherwise might be the case.
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 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 Revolver to pay distributions to its limited partners.
In addition, subject to certain conditions, the 8.75% Notes, the Term Loan, and the Revolver 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 our assets to WMLP and its

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subsidiaries, which will not be restricted subsidiaries or guarantors under the 8.75% Notes, Term Loan or borrowers under the Revolver.
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, 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, 2016, approximately 57% of our total workforce is represented by two labor unions, the IUOE 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. 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. 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.
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 acquisition of the Canadian mines, 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 acquisition of the Canadian mines, 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 throughout 2015 weakened considerably before improving slightly at the beginning of 2016 and then stabilizing at a relatively weak position for the remainder of 2016. If the 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 entities 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

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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.
The U.S. federal government has proposed the elimination of certain key U.S. federal income tax preferences relating to coal exploration and development. The 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.

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.

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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 2016, 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;
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. The 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;

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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 effect on our financial condition and results of operations. For additional information regarding specific regulations that impact our operations, see Item 1 - Business - Material Effects of 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 Climate Action Plan announced in June 2013, the EPA issued in August 2015 final standards for GHG emissions from existing fossil-fuel fired power plants, as well as new, modified and reconstructed fossil-fuel fired power plants. The Clean Power Plan sets standards

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for existing sources as stringent state-specific carbon emission rates to be phased in between 2020 and 2030. The rule would give states the discretion to use a variety of approaches - including cap-and-trade programs - to meet the standard. In February of 2016, however, the Supreme Court issued an order staying the Clean Power Plan pending judicial review of the rule by the U.S. Court of Appeals for the D.C. Circuit as well as potential review by the Supreme Court. The D.C. Circuit issued an expedited briefing schedule for challenges to the rule, and an en banc court heard oral argument on September 27, 2016. However, the Trump Administration has indicated that it plans to repeal the rule and it is uncertain whether it will be replaced. The U.S. Congress has considered, and in the future may again consider, legislation governing GHG emission, including “cap and trade” legislation that would establish a cap on emissions of GHGs covering much of the economy in the United States and would require most sources of GHG emissions to obtain GHG emission “allowances” corresponding to their annual emissions of GHGs. In addition, coal-fired power plants, including new coal-fired power plants or capacity expansions of existing plants, have become subject to opposition by environmental groups seeking to curb the environmental effects of GHG emissions. It is difficult to predict at this time the effect these rules would have on our revenues and profitability. For additional information, see Item 1 - Business - Material Effects of Regulation - U.S. Regulation.
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 our Canadian mines 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 Canadian coal production in the long-term could be reduced unless certain existing units or new units of the customers served by the Canadian mines 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.
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 2016 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 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 combating 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. See Item 1 - Business - Material Effects of Regulation - Canadian Regulation.
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

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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.
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.
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 and the issuance of the Stream Protection Rule by the OSM in December 2016. An inability to obtain the necessary permits to conduct WMLP’s mining operations or an inability to comply with the requirements of applicable permits could reduce WMLP’s production and cash flows, which could adversely affect its business, financial condition and/or results of operations and our cash flow.
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. The EPA intends to issue or has issued a number of significant regulations that will impose more stringent requirements relating to air, water and waste controls on electric generating units. These rules include the EPA’s final rule for CCR management, announced in December 2014, that further regulates the handling of wastes from the combustion of coal. In April 2014, the U.S. Supreme Court upheld the EPA’s Cross-State Air Pollution Rule, which would require stringent reductions in emissions of nitrogen oxides and sulfur dioxide from power plants in much of the U.S. For more details, see Item 1 - Business - Material Effects of Regulation - Mercury Air Standards and Clean Air Interstate Rule and Cross-State Air Pollution Rule (“CAIR”) and Cross-State Air Pollution Rule. In May 2014, the EPA Administrator signed a final rule that establishes requirements for cooling water intake structures for the withdrawal of cooling water by electric generating plants; the rule is anticipated to affect over 500 power plants.
Considerable uncertainty is associated with air emissions initiatives, and it is unclear how the Trump Administration will approach both previous rules and new rulemakings. New regulations are in the process of being developed, and many existing and potential regulatory initiatives are subject to review by federal or state agencies or the courts. Stringent air emissions limitations are already in place, and these limitations will likely require significant emissions control expenditures for many coal-fired power plants. For example, the owners of Units 3 & 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

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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 acquisition of the Canadian mines. Specifically, the Alberta Environmental Protection and Enhancement Act (“EPEA”) and its 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 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 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;

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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, 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 acquisitions of San Juan, Buckingham, WMLP and Canadian mines, 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.

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The challenges involved in integration include:
integrating the operations, processes, people and technologies;
coordinating and integrating regulatory, benefits, operations and development functions;
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 functions; and
identifying the potential unknown liabilities associated with these 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 these 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

48


imposition of tariffs, quotas, trade barriers and other trade protection measures, in addition to import or export licensing requirements imposed by various foreign countries.
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 with the Buckingham and San Juan mines 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.


49


ITEM 1B
UNRESOLVED STAFF COMMENTS.
None.
ITEM 2
PROPERTIES.
See Item 1 - Business - Properties for specific information relating to our mining operations, properties and reserves.
ITEM 3
LEGAL PROCEEDINGS.
We are subject, from time-to-time, to various proceedings, lawsuits, disputes, and claims (“Actions”) arising in the ordinary course of our business. Many of these Actions raise complex factual and legal issues and are subject to uncertainties. We cannot predict with assurance the outcome of Actions brought against us. Accordingly, adverse developments, settlements, or resolutions may occur and may result in a negative impact on income in the quarter of such development, settlement, or resolution. However, we do not believe that the outcome of any current Action would have a material adverse effect on our financial results. See Note 20 - Commitments And Contingencies to the consolidated financial statements for a description of our pending legal proceedings, which information is incorporated herein by reference.

ITEM 4
MINE SAFETY 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 - Mine Safety Disclosure to this report on Form 10-K.


50


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 24, 2017, there were 1,055 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
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

 
 
 
 
2016
 
 
 
First Quarter
$
8.05

 
$
3.44

Second Quarter
$
10.03

 
$
6.15

Third Quarter
$
10.44

 
$
7.49

Fourth Quarter
$
19.92

 
$
8.26

Dividend Policy
Holders of our common stock are entitled to receive such dividends as our board of directors 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 Term Loan, San Juan Loan and the Revolver 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 of directors 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
During 2016, we did not make any purchases of our common shares and no such purchases were made on our behalf.
Stock Performance Graph
The following performance graph compares the cumulative total stockholder return on our common stock for the five-year period December 31, 2011 through December 31, 2016 with (i) the cumulative total return over the same period of the NASDAQ Financial Index, (ii) the cumulative total return over the same period of the SPDR S&P Metals and Mining Index, and (iii) our former and current peer group index, which consisted 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, 2011;
All dividends were reinvested;
Annual re-weighting of the peer group indices; and
You continued to hold your investment through December 31, 2016.

51


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.
wlbstockperformancegraph.jpg
 
At December 31,
Company/Market/Peer Group
2011
 
2012
 
2013
 
2014
 
2015
 
2016
Westmoreland Coal Company
$
100.00

 
$
73.25

 
$
151.29

 
$
260.47

 
$
46.12

 
$
138.59

NASDAQ Financial Index
$
100.00

 
$
117.82

 
$
167.48

 
$
175.94

 
$
187.32

 
$
236.94

SPDR S&P Metals and Mining Index (2)
$
100.00

 
$
93.40

 
$
88.37

 
$
66.04

 
$
32.67

 
$
67.31

Peer Group Index(3)
$
100.00

 
$
80.78

 
$
81.69

 
$
63.39

 
$
16.53

 
$
45.37

(2) In 2015, we used the NYSE MKT Composite Index. In 2016, we switched to SPDR S&P Metals and Mining Index as it was more representative of investor return within the mining industry.
(3) 2016 and 2015 Peer Groups: Alliance Resource Partners LP, Arch Coal, Cloud Peak Energy, Consol Energy, and Peabody Energy


52


ITEM 6
SELECTED FINANCIAL DATA.
Westmoreland Coal Company and Subsidiaries
The following tables set forth selected historical consolidated financial data, for the periods and as of the dates indicated, that should be read in conjunction with Item 7 - Management’s Discussion and Analysis of Financial Condition and Results of Operations and our consolidated financial statements and notes thereto included in Item 8 - Financial Statements and Supplementary Data of this Form 10-K. We derived the consolidated statements of operations and cash flow data for the years ended December 31, 2016, 2015, and 2014 and our consolidated balance sheet data as of December 31, 2016 and 2015 from our audited financial statements included in Item 8 - Financial Statements and Supplementary Data of this Form 10-K. Periods prior to December 31, 2016 have been restated to correct errors identified in previously issued consolidated financial statements. Please refer to Note 2 - Restatement Of Previously Issued Consolidated Financial Statements and Note 22 - Quarterly Financial Data (Unaudited) to the consolidated financial statements contained in Item 8 - Financial Statements and Supplementary Data of this Form 10-K. The consolidated statements of operations and cash flow data for the years ended December 31, 2013 and 2012 and our consolidated balance sheet data as of December 31, 2014, 2013 and 2012 have been revised and restated to reflect the impact of the adjustments resulting from the revision and the restatement, but such restated data has not been audited. Our historical results are not necessarily indicative of future results.
 
2016(5)
 
2015
 
2014(5)
 
2013
 
2012
 
 
 
Restated
 
Restated
 
Restated
 
Restated
Consolidated Statements of Operations Information
(In thousands, except per share amounts)
Revenues
$
1,477,960

 
$
1,419,518

 
$
1,131,000

 
$
686,055

 
$
609,410

Operating income (loss)(1)
38,130

 
(145,696
)
 
(48,664
)
 
20,319

 
21,366

Net loss applicable to common shareholders(2)
(27,101
)
 
(213,645
)
 
(176,684
)
 
(9,204
)
 
(16,092
)
Per common share (basic and diluted):
 
 
 
 
 
 
 
 
 
Loss from continuing operations
$
(1.56
)
 
$
(12.24
)
 
$
(11.09
)
 
$
(0.78
)
 
$
(1.51
)
Net loss applicable to common shareholders
(1.47
)
 
(11.93
)
 
(11.08
)
 
(0.64
)
 
(1.15
)
Consolidated Balance Sheet Information (end of period)
 
 
 
 
 
 
 
 
 
Net property, plant and equipment
$
835,521

 
$
746,842

 
$
986,603

 
$
538,946

 
$
564,368

Total assets(3)
1,584,909

 
1,415,979

 
1,740,389

 
881,427

 
874,859

Total debt(3)
1,109,066

 
1,020,179

 
959,312

 
322,459

 
342,570

Total deficit
(690,117
)
 
(662,901
)
 
(400,876
)
 
(236,119
)
 
(329,428
)
Other Consolidated Data
 
 
 
 
 
 
 
 
 
Net cash provided by (used in):
 
 
 
 
 
 
 
 
 
Operating activities
$
151,934

 
$
45,562

 
$
50,353

 
$
80,717

 
$
57,144

Investing activities
(155,694
)
 
(70,801
)
 
(432,772
)
 
(21,897
)
 
(123,534
)
Financing activities
40,122

 
36,723

 
338,706

 
(29,320
)
 
67,217

Capital expenditures
46,132

 
77,921

 
50,326

 
28,591

 
21,032

Adjusted EBITDA(4)
271,855

 
222,832

 
187,669

 
127,634

 
114,195

Tons sold
54,685

 
53,334

 
44,849

 
24,927

 
21,745

____________________
(1)
Includes:
a.
Asset impairment charges of $136.2 million in 2015, comprised of $133.1 million at ROVA and $3.1 million at Coal Valley.
b.
Derivative (gain)/loss of $(24.1) million, $5.6 million and $31.1 million in 2016, 2015 and 2014, respectively.
c.
Restructuring charges of $0.7 million, $15.0 million and $5.1 million in 2015, 2014 and 2013, respectively.
(2)
Includes income tax benefit of $46.1 million in 2016 from the acquisition of the San Juan mine. In 2015, this line item included an income tax benefit of $19.9 million from the amalgamation of our Canadian entities into Prairie Mines & Royalty ULC. Also includes Loss on extinguishment of debt of $5.4 million, $49.2 million, $0.1 million and $2.0 million in 2015, 2014, 2013 and 2012, respectively.
(3)
Due to the adoption of ASU 2015-03 on January 1, 2016 and ASU 2015-17 on December 31, 2015, total assets for years shown are presented net of current deferred tax assets as well as debt discounts and unamortized debt issuance costs. Further, in conjunction with the adoption of ASU 2015-03, total debt for years shown are also presented net of debt discounts and unamortized debt issuance costs.
(4)
Adjusted EBITDA, a non-GAAP measure, is defined and reconciled to net loss at the end of Item 6 - Selected Financial Data.
(5)
On April 28, 2014, we completed the Canadian Acquisition. On December 31, 2014, we acquired WMLP. On January 31, 2016, we acquired the San Juan mine. Our results of operations, balance sheets, and other consolidated data include the acquired entities subsequent to their respective dates of acquisition.
We did not declare cash dividends on common shares for the five years ended December 31, 2016. The financial data presented above should be read in conjunction with Item 7 - Management’s Discussion and Analysis of Financial Condition and Results of Operations of this report, which includes a discussion of factors that materially affect the comparability of the information presented, and in conjunction with our consolidated financial statements included in this report.

53


Five-Year Review Restatement Reconciliations
For the years ended 2015 and 2014, see Note 2 - Restatement Of Previously Issued Consolidated Financial Statements to the consolidated financial statements for a reconciliation between amounts previously reported and now restated on the five-year review table. The following table reconciles previously reported amounts to restated amounts for the years 2013 and 2012:
 
2014
 
2013
 
2012
 
Reported
Adjustments
Restated
 
Reported
Adjustments
Restated
 
Reported
Adjustments
Restated
Consolidated Statements of Operations Information
(In thousands, except per share data)
Revenues
$
1,115,992

$
15,008

$
1,131,000

 
$
674,686

$
11,369

$
686,055

 
$
600,437

$
8,973

$
609,410

Operating income (loss)
(42,975
)
(5,689
)
(48,664
)
 
25,362

(5,043
)
20,319

 
28,872

(7,506
)
21,366

Net loss applicable to common shareholders
(173,118
)
(3,568
)
(176,686
)
 
(6,057
)
(3,147
)
(9,204
)
 
(8,586
)
(7,506
)
(16,092
)
Per common share (basic and diluted):
 
 
 
 
 
 

 
 
 
 
Loss from continuing operations
$
(10.86
)
$
(0.23
)
$
(11.09
)
 
$
(0.56
)
$
(0.22
)
$
(0.78
)
 
$
(0.97
)
$
(0.54
)
$
(1.51
)
Net loss applicable to common shareholders
(10.86
)
(0.22
)
(11.08
)
 
(0.42
)
(0.22
)
(0.64
)
 
(0.61
)
(0.54
)
(1.15
)
Consolidated Balance Sheet Information (end of period)
 
 
 
 
 
 

 
 
 
 
Net property, plant and equipment
$
927,662

$
58,941

$
986,603

 
$
490,036

$
48,910

$
538,946

 
$
512,840

$
51,528

$
564,368

Total assets
1,791,020

(50,631
)
1,740,389

 
929,307

(47,880
)
881,427

 
917,696

(42,837
)
874,859

Total debt
959,312


959,312

 
322,459


322,459

 
342,570


342,570

Total deficit
(349,445
)
(51,431
)
(400,876
)
 
(187,879
)
(48,240
)
(236,119
)
 
(286,231
)
(43,197
)
(329,428
)
Other Consolidated Data
 
 
 
 
 
 

 
 
 
 
Net cash provided by (used in):
 
 
 
 
 
 

 
 
 
 
Operating activities
$
50,353

$

$
50,353

 
$
80,717

$

$
80,717

 
$
57,144

$

$
57,144

Investing activities
(432,772
)

(432,772
)
 
(21,897
)

(21,897
)
 
(123,534
)

(123,534
)
Financing activities
338,706


338,706

 
(29,320
)

(29,320
)
 
67,217


67,217

Capital expenditures
50,326


50,326

 
28,591


28,591

 
21,032


21,032

Adjusted EBITDA
175,351

12,318

187,669

 
116,265

11,369

127,634

 
105,432

8,763

114,195

Tons sold
44,849


44,849

 
24,927


24,927

 
21,745


21,745

Reconciliation of Adjusted EBITDA to Net Loss
EBITDA is defined as earnings before interest expense, interest income, income taxes, depreciation, depletion, amortization and accretion expense. Adjusted EBITDA is defined as EBITDA before certain charges to income such as restructuring, impairment, debt extinguishment, foreign exchange and derivative losses and/or gains which are not considered part of earnings from operations for comparison purposes to other companies’ normalized income. EBITDA and Adjusted EBITDA are supplemental measures of financial performance that are not required by, or presented in accordance with, GAAP. EBITDA and Adjusted EBITDA are key metrics used by us to assess our operating performance and as a basis for strategic planning and forecasting and we believe that EBITDA and Adjusted EBITDA are useful to an investor in evaluating our operating performance because these measures:
are used widely by investors to measure a company’s operating performance without regard to items excluded from the calculation of such terms, which can vary substantially from company to company depending upon accounting methods and book value of assets, capital structure and the method by which assets were acquired, among other factors;
are used by rating agencies, lenders and other parties to evaluate our creditworthiness; and
help investors to more meaningfully evaluate and compare the results of our operations from period to period by removing the effect of our capital structure and asset base from our operating results.
Neither EBITDA nor Adjusted EBITDA is a measure calculated in accordance with GAAP. The items excluded from EBITDA and Adjusted EBITDA are significant in assessing our operating results. EBITDA and Adjusted EBITDA have limitations as analytical tools, and should not be considered in isolation from, or as a substitute for, analysis of our results as reported under GAAP. For example, EBITDA and Adjusted EBITDA:
do not reflect our cash expenditures or future requirements for capital and major maintenance expenditures or contractual commitments;
do not reflect income tax expenses or the cash requirements necessary to pay income taxes;

54


do not reflect changes in, or cash requirements for, our working capital needs; and
do not reflect the significant interest expense, or the cash requirements necessary to service interest or principal payments, on certain of our debt obligations.
In addition, although depreciation and amortization are non-cash charges, the assets being depreciated and amortized will often have to be replaced in the future, and EBITDA and Adjusted EBITDA do not reflect any cash requirements for such replacements. Other companies in our industry and in other industries may calculate EBITDA and Adjusted EBITDA differently from the way that we do, limiting their usefulness as comparative measures. Because of these limitations, EBITDA and Adjusted EBITDA should not be considered as measures of discretionary cash available to us to invest in the growth of our business. We compensate for these limitations by relying primarily on our GAAP results and using EBITDA and Adjusted EBITDA only as supplemental data. The tables below show how we calculated Adjusted EBITDA, including a breakdown by segment, and reconcile Adjusted EBITDA to net income (loss), the most directly comparable GAAP financial measure.
Reconciliation of Adjusted EBITDA to Net Loss
For the Years Ended December 31,
 
2016
 
2015
 
2014
 
2013
 
2012
 
 
 
Restated
 
Restated
 
Restated
 
Restated
 
(In thousands)
Net loss
$
(28,872
)
 
$
(219,095
)
 
$
(176,746
)
 
$
(11,274
)
 
$
(21,168
)
 
 
 
 
 
 
 
 
 
 
Income tax (benefit) expense
(48,059
)
 
(19,890
)
 
23

 
(6,678
)
 
90

Interest income
(7,435
)
 
(7,993
)
 
(6,400
)
 
(1,366
)
 
(1,496
)
Interest expense
121,819

 
101,311

 
82,320

 
39,937

 
42,677

Depreciation, depletion and amortization
185,267

 
140,328

 
109,361

 
74,430

 
63,699

Accretion of ARO
40,423

 
38,892

 
31,028

 
21,894

 
21,904

Amortization of intangible assets and liabilities
(810
)
 
(1,010
)
 
138

 
665

 
658

EBITDA
262,333

 
32,543

 
39,724

 
117,608

 
106,364

 
 
 
 
 
 
 
 
 
 
Restructuring charges

 
656

 
14,989

 
5,078

 

Loss (gain) on foreign exchange
715

 
(3,674
)
 
4,016

 

 

Loss on impairment

 
136,210

 

 

 

Loss on extinguishment of debt

 
5,385

 
49,154

 
64

 
1,986

Acquisition related costs(1)
568

 
5,959

 
26,785

 

 

Customer payments received under loan and lease receivables(2)
13,064

 
27,128

 
12,388

 

 

Derivative loss (gain)
(24,055
)
 
5,587

 
31,100

 

 

Loss (gain) on sale/disposal of assets and other adjustments
11,646

 
5,290

 
3,431

 
(438
)
 
(195
)
Share-based compensation
7,584

 
7,748

 
6,082

 
5,322

 
6,040

Adjusted EBITDA
$
271,855

 
$
222,832

 
$
187,669

 
$
127,634

 
$
114,195

Increase to Adjusted EBITDA arising from restatement included above(3)
$
6,138

 
$
6,166

 
$
12,318

 
$
11,369

 
$
8,763

__________________
(1)
Includes acquisition and transition costs included in Selling and administrative on the Consolidated Statements of Operations and the impact of cost of sales related to the sale of inventory written up to fair value in the acquisition of the Canadian mines.
(2)
Represents a return of and on capital. These amounts are not included in operating income or operating cash flows, as the capital outlays are treated as loan and lease receivables, but are included within Adjusted EBITDA so that the cash received by the Company is treated consistently with all other contracts within the Company that do not result in loan and lease receivable accounting.
(3)
2016 includes $3.7 million from the first three quarters of the year which were restated, as well as a $2.4 million impact in the fourth quarter of 2016 arising from consistent application of the revised accounting.

55


ITEM 7
MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS.
The following discussion and analysis contains forward-looking statements and estimates that involve risks and uncertainties. Actual results could differ materially from these estimates. Factors that could cause or contribute to differences from estimates include those discussed under Cautionary Note Regarding Forward-Looking Statements and Item 1A - Risk Factors.
This discussion should be read in conjunction with our consolidated financial statements and notes thereto contained in Item 8 - Financial Statements and Supplementary Data of this Annual Report on Form 10-K.
Restatement of Consolidated Financial Statements
As discussed in the Explanatory Note to this Form 10-K and Note 2 - Restatement Of Previously Issued Consolidated Financial Statements to the consolidated financial statements, this Form 10-K restates the Company’s previously issued consolidated financial statements and related disclosures in Item 8 - Financial Statements and Supplementary Data to reflect the correction of certain errors. Accordingly, the Management’s Discussion and Analysis of Financial Condition and Results of Operations set forth below reflects the effects of this restatement.
Overview

See Item 1 - Business - Overview and Item 1 - Business - Segment Information for a general description of our business and our business segments.
We sell almost all of our coal and electricity production under long-term agreements. Our long-term coal contracts 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. We refer to these contracts as “cost protected” contracts. For our contracts that are not cost protected in nature, we have exposure to inflation and price risk for supplies used in the normal course of production such as diesel fuel and explosives. We manage these items through strategic sourcing contracts in normal quantities with our suppliers and may use derivatives from time-to-time.
One of the major factors affecting the volume of coal that we sell in any given year is the demand for coal-generated electric power, as well as the specific demand for coal by our customers. Numerous factors affect the demand for electric power and the specific demands of customers including weather patterns, the presence of hydro or wind in our particular energy grids, environmental and legal challenges, political influences, energy policies, international and domestic economic conditions, power plant outages and other factors discussed herein.

Recent Developments
Lost Contracts
See Item 1 - Business - Coal - U.S. Segment Properties for a description of contracts lost or for which the length of coal supply terms were shortened.
Entry into Substitute Energy Purchase Agreement
See Item 1 - Business - Power Segment for a description of the Amending Agreement affecting our ROVA Consolidated Agreement.


56


Results of Operations
2016 Compared to 2015
Summary
The following table shows the comparative consolidated results and changes between periods:
 
Year Ended December 31,
 
 
 
Restated
 
Increase / (Decrease)
 
2016
 
2015
 
$
 
%
 
(In millions)
Revenues
$
1,478.0

 
$
1,419.5

 
$
58.5

 
4.1
%
Net loss applicable to common shareholders
(27.1
)
 
(213.6
)
 
186.5

 
87.3
%
Adjusted EBITDA(1)
271.9

 
222.8

 
49.1

 
22.0
%
____________________
(1)
Adjusted EBITDA , a non-GAAP measure, is defined and reconciled to net income (loss) in Item 6 - Selected Financial Data.

Consolidated revenue increased due to $184.4 million in revenue generated by San Juan, offset by softness at other locations. Our net loss improved by $186.5 million due to the following:

$136.2 million of impairment from 2015 that didn’t occur in 2016;
$14.1 million increase in operating income from WMLP due to lower fuel and labor costs at our Ohio mines and the impact of cost savings initiatives at our Kemmerer mine which are expected to continue into the future;
$29.6 million improvement in derivative gain/loss;
$28.3 million more in income tax benefit from the first quarter release of our valuation allowance on our net operating loss deferred tax asset arising from the San Juan Acquisition; and
$20.5 million increase in interest expense due to our higher debt levels arising from the San Juan Acquisition offset the above improvements to income.

Consolidated Adjusted EBITDA increased as a result of strong operating results in our Coal - U.S. and Coal - WMLP segments slightly offset by lower loan and lease receivable payments in our Coal - Canada segment.
Coal - U.S. Segment Operating Results
The following table summarizes key metrics for the Coal - U.S. segment. As a result of the Kemmerer Drop, results for all periods presented reflect the Kemmerer mine as part of the Coal - WMLP segment and not part of the Coal - U.S. segment.
 
Year Ended December 31,
 
 
 
Restated
 
Increase / (Decrease)
 
2016
 
2015
 
$
 
%
 
(In millions)
Revenues
$
651.7

 
$
552.7

 
$
99.0

 
17.9
%
Operating income (loss)
(8.1
)
 
2.2

 
(10.3
)