WESTMORELAND COAL Co - FORM 10-K - April 2, 2018

Attached files

file filename
EX-10.02 - EXHIBIT 10.02 - WESTMORELAND COAL Coexh1002-form10xkfy2017.htm
EX-95.1 - EXHIBIT 95.1 - WESTMORELAND COAL Coexh951-safety.htm
EX-32 - EXHIBIT 32 - WESTMORELAND COAL Coexh32-ceocfosignatures.htm
EX-31.2 - EXHIBIT 31.2 - WESTMORELAND COAL Coexh312-cfosignature.htm
EX-31.1 - EXHIBIT 31.1 - WESTMORELAND COAL Coexh311-ceosignature.htm
EX-23.1 - EXHIBIT 23.1 - WESTMORELAND COAL Coexh231-eyconsent.htm
EX-21.1 - EXHIBIT 21.1 - WESTMORELAND COAL Coexh211-listingofsubsidiari.htm
EX-10.66 - EXHIBIT 10.66 - WESTMORELAND COAL Coexh1066-form10xkfy2017.htm
EX-10.65 - EXHIBIT 10.65 - WESTMORELAND COAL Coexh1065-form10xkfy2017.htm
EX-10.61 - EXHIBIT 10.61 - WESTMORELAND COAL Coexh1061-form10xkfy2017.htm
EX-10.60 - EXHIBIT 10.60 - WESTMORELAND COAL Coexh1060-form10xkfy2017.htm
EX-10.59 - EXHIBIT 10.59 - WESTMORELAND COAL Coexh1059-form10xkfy2017.htm
EX-10.52 - EXHIBIT 10.52 - WESTMORELAND COAL Coexh1052-form10xkfy2017.htm

UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
 ______________________________________________________________
FORM 10-K
(Mark One)
x ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
For the fiscal year ended December 31, 2017
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
  ______________________________________________________________
wlblogo123116a01.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, a smaller reporting company or an emerging growth company. See the definitions of “large accelerated filer,” “accelerated filer,” “smaller reporting company” and “emerging growth company” in Rule 12b-2 of the Exchange Act.
Large Accelerated Filer
☐
Accelerated Filer
☒
Non-Accelerated Filer (do not check is smaller reporting company)
☐
Smaller Reporting Company
☐
 
 
Emerging Growth Company
☐
If an emerging growth company, indicate by check mark if the registrant has elected not to use the extended transition period for complying with any new or revised accounting standards provided to Section 13(a) of the Exchange Act. ☐
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, 2017 was $89,851,140.
There were 18,771,643 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 29, 2018.
  ______________________________________________________________

DOCUMENTS INCORPORATED BY REFERENCE
Portions of the Definitive Proxy Statement on Schedule 14A to be filed within 120 days after December 31, 2017, in connection with the Company’s 2018 Annual Meeting of Stockholders scheduled to be held on August 31, 2018, are incorporated by reference into Part III of this Annual Report on Form 10-K (“Annual Report” or “Form 10-K”).


WESTMORELAND COAL COMPANY
FORM 10-K
ANNUAL REPORT
TABLE OF CONTENTS
 
Item
 
Page
 
 
 
 
 
1
1A
1B
2
3
4
 
 
 
 
 
5
6
7
7A
8
9
9A
9B
 
 
 
 
 
10
11
12
13
14
 
 
 
 
 
15
16
 

3

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 Item 1A - Risk Factors and throughout this 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:

•
Adverse impacts to our business, financial condition, results of operations and cash flows resulting from the ongoing capital structure review, including our possible filing for bankruptcy protection under Chapter 11 of the United States Bankruptcy Code;
•
Adverse impacts to our business as a result of the audit opinion of our independent auditor containing an explanatory paragraph referencing our conclusion that substantial doubt exists as to our ability to continue as a going concern;
•
The impact of cross-acceleration and cross-default provisions between our debt and debt held by WMLP;
•
Our substantial level of indebtedness and our ability to adhere to financial covenants contained within the agreements governing indebtedness;
•
Our ability to generate sufficient cash flow;
•
Existing and future environmental 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 concentration of revenues derived from a small number of customers, and the creditworthiness of those customers;
•
Changes in our post-retirement medical benefit and pension obligations resulting from market volatility or changes in assumptions regarding our future expenses;
•
Inaccuracies in our estimates of our coal reserves, reclamation and/or mine closure obligations;
•
Potential limitations in obtaining bonding capacity and/or increases in our mining costs as a result of increased bonding expenses;
•
Business interruptions, including unplanned equipment failures, geological, hydrological or other conditions, and competition and/or conflicts with other resource extraction activities, caused by external factors;
•
Natural disasters and events, including blizzards, earthquakes, drought, floods, fire and storms, not all of which are covered by insurance;
•
Potential title defects or loss of leasehold interests in our properties, which could result in unanticipated costs or an inability to mine the properties;
•
Risks associated with cybersecurity and data leakage;
•
Our ability to continue to acquire and develop coal reserves through acquisition and to raise the associated capital necessary to fund our expansion;
•
Changes in our tax position resulting from ownership changes, our interest in WMLP, and changes in tax law;
•
Risks associated with our interest in WMLP;
•
The availability and costs of key supplies or commodities, such as transportation, key equipment and materials;
•
Competition within our industry and with producers of competing energy sources;
•
Our relationships with, and other conditions affecting, our customers, including how power prices and consumption patterns affect our customers’ decisions to run their plants;
•
Changes in the export and import markets for coal products;
•
Extensive government regulations both in the US. and Canada, including existing and potential future legislation, treaties and regulatory requirements;
•
The impacts of climate change concerns;
•
Our ability to obtain and/or renew operating permits;
•
The potential failure to meet the continued listing requirements of the NASDAQ Capital Market;
•
Our ability to effectively manage and integrate acquisitions;
•
Risks associated with our business outside the United States;
•
Other factors that are described under the heading “Risk Factors” found in this Annual Report on Form 10-K.


4

Unless otherwise specified, the forward-looking statements in this report speak as of the filing date of this Annual 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.

5

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, 2017, 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 49.7 million tons of coal in 2017.
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 2,950 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. As of December 31, 2017, our operations included 12 wholly-owned actively producing coal mines in the U.S. and Canada, a char production facility, and a 50% stake in an activated carbon plant. We also own the general partner of and, at December 31, 2017, own 93.94% of the total equity interest in, Westmoreland Resource Partners, LP (“WMLP”), which is a publicly traded limited partnership that owns and actively operates four mining complexes in Ohio and one mine in Wyoming. The following map shows our operations as of the date of this filing:
wlbmapitem1201710kincludia01.jpg

6

Restructuring Activities

On March 7, 2018, we announced that we have retained Centerview Partners as financial advisors and Alvarez & Marsal North America, LLC as restructuring advisors, to explore strategic alternatives to strengthen the Company’s balance sheet and maximize the value of the Company, which may include, but not limited to, seeking reorganization under Chapter 11 of the U.S. Bankruptcy Code. We have engaged in discussions with certain stakeholders regarding strategic alternatives to restructure our balance sheet. We continue to retain Kirkland & Ellis LLP as our legal advisor to assist the Board and management team with the strategic review process.
Segment Information
We classify our business into six segments: Coal - U.S., Coal - Canada, Coal - WMLP, Power, Heritage and Corporate. Our principal operating segments for the year ended December 31, 2017 were our Coal - U.S., Coal - Canada, Coal - WMLP and Power segments, however, during the fourth quarter of 2017 we sold all of the assets that comprised our Power operating segment and terminated all related power agreements. 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. ("WRMI"), through which we have elected to retain some of our operating risks.
Due to the Kemmerer Drop (see Note 2 - 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.
See Note 19 - Business Segment Information to the consolidated financial statements for more information regarding revenue, operating income (loss) and total assets for each of our segments.
Coal Segments
General
Each of our mining segments focuses on 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. Most of our 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 one year up to fifteen years. Our current coal sales contracts have a weighted average remaining term of approximately six years. See our segment financial statements at Note 19 - 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 on Form 10-K. In determining whether our proven and probable coal reserves meet this economic and legal standard, we take into account, among other things, our potential ability or inability to obtain mining permits, the possible necessity of revising mining plans, changes in future cash flows caused by changes in estimated future costs, changes in mining permits, variations in quantity and quality of coal, and varying levels of demand and their effects on selling prices. The following table provides coal reserve quantities by segment from mines we own or control as of December 31, 2017:
 
Coal - U.S.
 
Coal - Canada
 
Coal - WMLP2
 
Total
 
(In thousands of tons)
Coal reserves1:
 
 
 
 
 
 
 
     Proven
316,330
 
274,159
 
108,786
 
699,275
     Probable
1,562
 
19,575
 
11,730
 
32,867
Total proven and probable reserves3
317,892
 
293,734
 
120,516
 
732,142
Permitted reserves
161,846
 
241,966
 
62,597
 
466,409
Current year production
18,843
 
22,462
 
6,642
 
47,947
____________________
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:


7

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 93.94% of the total outstanding equity interests (as of December 31, 2017).

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 8 - 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 (see Note 2 - Acquisitions to the consolidated financial statements for details). 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 (see Note 2 - Acquisitions to the consolidated financial statements for details). 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 (See Note 8 - Debt And Lines Of Credit to the consolidated financial statements for details).

8

The following tables provide information about mines in our Coal - U.S., Coal - Canada, and Coal - WMLP segments as of December 31, 2017 (all tons data presented in thousands):

Coal - U.S. Mines
Colstrip
Absaloka
Savage
San Juan
Jewett1
Beulah
Buckingham
Haystack2
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
Kiewit Mining Group, Inc., purchased 2017
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
Haystack Coal Company
County, State
Rosebud & Treasure, Montana
Big Horn, Montana
Richland, Montana
San Juan, New Mexico
Leon & Freestone & Limestone, Texas
McLean & Oliver, North Dakota
Perry, Ohio
Uinta, Wyoming
Proven reserves
241,087
27,565
3,685
11,445
—
5,038
14,707
12,803
Probable reserves
—
—
—
—
—
—
1,562
—
Total reserves
241,087
27,565
3,685
11,445
—
5,038
16,269
12,803
Permitted reserves
89,014
27,565
3,685
11,445
—
1,065
16,269
12,803
2017 tons produced
8,636
3,566
273
5,327
—
432
609
N/A
Production capacity
13,300
7,500
400
9,000
N/A
2,500
1,000
N/A
2017 tons sold
8,630
3,573
273
6,110
—
437
944
N/A
2016 tons sold
8,812
4,157
309
5,417
3,690
948
729
N/A
2015 tons sold
9,626
5,844
271
 N/A
3,357
2,136
1,246
N/A
Estimated mine life with current plan
2029
2022
2028
2022
N/A
2019
2040
2037
Lessor3
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
Private parties
Lease term
Varies
Through exhaustion
Varies
Varies
Varies
Varies
Varies
Through exhaustion
Coal seam
Rosebud
Rosebud-McKay
Pust
Fruitland No. 8
N/A
Schoolhouse, Beulah-Zap
Middle Kittanning
Adaville series
Coal type
Sub-bituminous
Sub-bituminous
Lignite
Sub-bituminous
N/A
Lignite
Bituminous
Sub-bituminous
Approx. heat content of reserves (BTU/lb.)
8,500
8,580
6,505
10,275
 N/A
6,974
13,203
9,600
Approx. sulfur content of reserves (%)
0.69
0.61
0.45
1.04
N/A
0.61
2.23
0.31
Major customers3
Colstrip 1&2, Colstrip 3&4
Xcel Energy, Western Fuels Assoc.
Montana Dakota Utilities, Sidney Sugars
Public Service of New Mexico
N/A
Montana Dakota Utilities
AEP, Glatfelter
N/A
Delivery method
Truck, rail, conveyor belt
Truck, rail
Truck
Truck, conveyor belt
N/A
Rail
Truck, rail
N/A
Machinery
4 draglines, load-out facility
1 dragline, load-out facility
1 dragline
Longwall
1 dragline (customer owned), shovel
1 dragline, load-out facility
Prep plant, rail & truck load-out facility, 6 continuous miners
N/A
Gross Land, Mineral Rights, Property, Plant & Equipment (in millions)
$265.8
$166.3
$11.7
$216.4
$162.4
$84.4
$42.9
$7.1
Year complex opened
1968
1974
1958
1973
1985
1963
2007
N/A
____________________
1 Reclamation phase of mine life during 2017.
2 Reserves acquired for future development.
3 American Electric Power Company, Inc. (“AEP”).

9

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
18,071
72,283
16,759
4,859
45,001
117,186
Probable reserves
—
2,205
3,021
5,899
—
8,450
Total reserves
18,071
74,488
19,780
10,758
45,001
125,636
Permitted reserves
18,071
74,488
19,780
4,859
45,001
79,767
2017 tons produced
1,350
5,560
3,499
2,168
3,587
6,298
Production capacity
3,300
6,600
4,000
2,500
3,850
6,800
2017 tons sold
1,337
5,560
3,923
2,224
3,458
6,248
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
Estimated mine life with current plan
2029
2030
2026
2019
2029
2030
Lessor4
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 of reserves (BTU/lb.)
7,716
8,268
7,088
10,800
5,771
7,004
Approx. sulfur content of reserves (%)
0.44
0.22
0.54
0.30
 <0.99
0.64
Major customers4
ATCO Power
 Capital Power
 ATCO Power, TransAlta
 International & domestic
 SaskPower
 SaskPower
Delivery method
 Trucks
 Trucks
 Trucks
 Rail
 Rail
 Trucks
Machinery
1 dragline (customer owned)
2 draglines (customer owned), shovels
2 draglines (1 customer owned)
1 dragline, 2 shovels
2 draglines (1 customer owned)
4 draglines (1 customer owned)
Gross Land, Mineral Rights, Property, Plant & Equipment (in millions)
$25.7
$4.7
$51.0
$37.9
$54.6
$170.7
Year complex opened
1956
1988
1984
1978
1978
1973
____________________
4 Alberta Power (2000) Ltd. (“ATCO Power”); Saskatchewan Power Corporation (“SaskPower”).

10

Coal - WMLP Mines
Cadiz
Tuscarawas
Belmont
New Lexington
Noble5
Plainfield5
Muhlenberg7
Tusky5, 8
Kemmerer
Previously owned by
These mines were previously owned by Oxford Resource Partners, LP which is the predecessor entity to Westmoreland Resource Partners, LP.
Chevron Mining Inc., purchased 2012
Currently owned by
 The Ohio mines are owned by Oxford Mining Company, LLC. The Muhlenberg mine located in Kentucky is owned by Oxford Mining Company - Kentucky, LLC.
Westmore- land Kemmerer, LLC
County, State
Jefferson, Harrison, Ohio
Columbiana, Coshocton, Stark, Tuscarawas, Ohio
Belmont, Ohio
Perry, Athens & Morgan, Ohio
Noble & Guernsey, Ohio
Muskingum, Guernsey & Coshocton, Ohio
Muhlenberg, Kentucky
Harrison & Tuscarawas, Ohio
Lincoln, Wyoming
Proven reserves
4,065
4,301
7,414
4,839
—
3,622
—
14,581
69,964
Probable reserves
439
—
306
56
—
—
—
2,062
8,867
Total reserves
4,504
4,301
7,720
4,895
—
3,622
—
16,643
78,831
Permitted reserves
4,133
1,740
1,300
708
—
1,070
—
16,643
37,003
2017 tons produced
1,573
211
400
228
—
—
6
—
4,224
Production capacity
1,500
250
1,000
500
 N/A
 N/A
 N/A
 N/A
4,500
2017 tons sold
2,232
211
396
235
—
—
6
—
4,294
2016 tons sold
2,558
456
333
390
—
—
—
—
4,106
2015 tons sold
2,125
673
644
551
17
—
—
—
4,471
Estimated mine life with current plan
2023
2021
2023
2022
N/A
N/A
N/A
N/A
2026
Lessor6
 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 of reserves (BTU/lb.)
11,465
11,771
11,735
11,708
 N/A
11,711
 N/A
12,900
9,800
Approx. sulfur content of reserves (%)
2.80
3.70
4.50
3.80
 N/A
4.40
 N/A
2.00
0.69
Major customers6
 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
Shovel, loader, truck, dozer, auger
Loader, truck, dozer, auger, highwall miner
Loader, truck, dozer, auger, highwall miner
Loader, truck, dozer, auger
N/A
N/A
N/A
N/A
Trucks, shovels, dozers
Gross Land, Mineral Rights, Property, Plant & Equipment (in millions)
The Ohio & Kentucky mines' gross land, mineral rights, property, plant and equipment as of December 31, 2017 was $202.3 million.
$156.5
Year complex opened
2000
2003
1999
1993
2006
1990
2009
2003
1950
____________________
5 These mines were inactive during 2017.
6 American Electric Power Company, Inc. (“AEP”); East Kentucky Power Cooperative (“EKPC”).
7 Reclamation phase of mine life during 2017, however, incidental with performance of reclamation, tons were recovered and sold.
8 WMLP controls the reserves which are subleased to a third party.


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Coal - U.S. Segment Properties
Our Coal - U.S. segment is comprised of our wholly owned mines located in the United States, excluding our mines 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 2017, our Coal - U.S. segment derived approximately 83% of its revenues from coal sales to four customers: Public Service Company of New Mexico (36%), Colstrip Units 3&4 (24%), Colstrip Units 1&2 (12%) and American Electric Power Company, Inc. (11%). We sell the majority of our U.S. tons under contracts with a weighted average remaining supply obligation term of approximately three years.
San Juan. The San Juan mine was acquired on January 31, 2016 from BHP Billiton and supplies the requirements of 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 on June 30, 2022. As anticipated, at the end of 2017 the San Juan Generating Station shut down two of their four units which represents a 50% decrease in sales volume from the mine moving forward.
Prices under the coal supply agreement includes a fixed-base price per ton delivered for set quantities each contract year, a lower fixed-base price per ton delivered for additional tons delivered in excess of high-priced quantities, and a nominal fixed-base price per ton delivered for coal considered to be delivered from the stockpile existing at acquisition, for which the customer had previously paid for the related production costs. These fixed-base prices are adjusted quarterly based on changes in various cost and commodity indices. In addition to these per ton fees, we receive direct reimbursements for utility costs, leasing costs, and bond premiums.

We also have separate agreements with the customer for payments related to reclamation activities and ash hauling and disposal. Under these agreements, we receive fixed monthly fees and set payments per unit of activity for reclamation and ash hauling and disposal. These agreements extend beyond the term of the coal supply agreement and we will continue to receive payments for these activities until they are completed. We estimate the completion of ash hauling and disposal activities by the end of 2022, the end of most reclamation activities by the end of 2027, and the end of monitoring costs for reclamation by 2040.
Colstrip. The Colstrip mine has two long-term, cost-plus requirements contracts with the adjacent Colstrip Station power generating facility. These contracts provide for the reimbursement of defined fixed costs, variable costs, royalties and taxes, and any previously unfunded final reclamation costs. We additionally receive a profit component in the form of a per-ton management and incentive fee which are adjusted quarterly based on changes in specific indices. The Colstrip Units 3 & 4 agreement contains provisions for specific returns on capital investments. We currently sell approximately 2.3 million tons to Colstrip Units 1 & 2 annually. In December 2016, we were notified by the owners of Colstrip Units 1 & 2 that our coal supply agreement will terminate three years early at the end of 2019. We do not expect the termination of supply to Units 1 & 2 to impact our contract related to Colstrip Units 3 & 4, which provides for approximately 6.2 million tons per year and currently is set to expire at the end of 2019. As of the date of this filing, we are currently in negotiation to extend the contracts for both Colstrip Units 1 & 2 and Units 3 & 4 beyond 2019.
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 long-term coal supply agreement expiring on December 31, 2019 which includes payments at a set fixed-base price per ton delivered for each contract year with adjustments based on quality

12

measurements. Buckingham’s proximity to WMLP’s New Lexington complex allows us to use substitute tonnage supplied through a contract with WMLP.
Absaloka. The Absaloka mine markets coal primarily in the open market and has several contracts with remaining terms of up to two years with various parties. The prices for these contracts are set at a fixed-base price per ton delivered for each year with periodic adjustments based on changes in certain indices such as diesel fuel. 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.
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 a new agreement with Sidney Sugars in 2017 that expires on July 31, 2021 and with Lewis & Clark Station in 2018 that expires on December 31, 2020. Prices under the Lewis & Clark Station agreement are set at a fixed-base price per ton delivered for each year with periodic adjustments based on changes in electricity costs, diesel indices, depreciation, depletion and amortization ("DD&A") and CPI indices. Prices under the Sidney Sugars Incorporated agreement are set at a fixed-base price per ton delivered for each year with no subsequent adjustments unless our per ton mining costs are altered by changes in a law, regulation, government order or court order.
Beulah. The Beulah mine supplied coal to the Coyote Electric Generating Plant via conveyor belt and the Heskett Power Station by rail. We continue to provide coal to the Heskett Power Station under an agreement with an expiration date of December 31, 2021 in which payments are based on a fixed-base price per ton delivered, adjusted quarterly based on changes in various cost and commodity indices and quality adjustments. However, we no longer provide coal to the Coyote Electric Generating Plant as their agreement expired on May 31, 2016. Previously, we supplied approximately 2.5 million tons annually to the adjacent Coyote Electric Generating Plant.
Jewett. At our Jewett mine, our customer, NRG Texas Power (“NRG”), terminated our coal supply agreement on December 31, 2016. The agreement was a cost-plus arrangement in which the customer reimbursed us for all costs incurred in mining plus a set percentage management fee. Beginning in 2017, we entered the reclamation phase of the mine life where NRG is required to reimburse us for agreed upon base reclamation costs during final reclamation plus a variable percentage management fee. During the years ended December 31, 2016 and 2015, we supplied NRG with 3.7 million and 3.4 million tons of coal, respectively.
Haystack. WCC acquired Haystack Coal Company and associated coal reserves in January of 2017.  The reserve area is fully permitted and currently on care and maintenance. No production or development work occurred on the property in 2017.
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.
All of our mines in Canada are surface mines, five of which are mine-mouth operations where our mine is adjacent to the customer’s plant. The majority of our Canadian coal production is sold to Canadian utilities for electricity production, with a small percentage being exported to Asia. 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 $0.44 per ton in U.S. dollars as of December 31, 2017. 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.

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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 2017 our Coal - Canada segment derived approximately 86% of its revenues from coal sales to three customers: SaskPower (44%), Trafigura Pte. Ltd. (26%) and ATCO Power (16%). We sell the majority of our Canadian tons under contracts with a weighted average remaining supply obligation term of approximately nine years.
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. We supply coal from the mine on a requirements basis, via conveyor belt, to the adjacent generating units. Payments are based on reimbursement of all mining costs plus an incentive fee, corporate overhead fee, and an operating management fee. Our mine operating agreement 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 limits the contract to 2030.
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. The Estevan mine combines the Bienfait mine and the adjacent Boundary Dam mine. 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.
We have separate agreements with the customer for each mine. Payments are based on a fixed-base price per ton delivered for each contract, adjusted annually for changes in actual costs and indices, plus reimbursements for certain taxes and insurance. We also receive a fixed monthly payment regardless of tons delivered during the period, monthly incentives if we meet defined stripped coal reserves and stockpile levels, and annual incentives for meeting defined reclamation targets. The contracts include a combined obligation to purchase a minimum of 4.1 million tons of coal each year through 2019 and a minimum of 1.7 million tons of coal each year thereafter through the expiration date of December 31, 2024.
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 Alberta Power (2000) Ltd. ("ATCO Power"). We have separate agreements with the customer for each active pit. Payments are based on a fixed-base price per ton delivered for each contract adjusted annually for changes in actual costs and indices, plus reimbursements for certain taxes and insurance. We also receive set payments per unit of ash hauled from the customer’s plant. The contracts include a combined obligation to purchase a minimum of 1.2 million tons of coal each year through the expiration date of December 31, 2022.
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. The Poplar River mine owns and operates the railway from the mine to the generating station. We have a single coal supply agreement with the customer in which payments are based on a fixed-base price per ton delivered adjusted annually for changes in actual costs and indices, plus reimbursements for royalties, taxes, insurance, and other miscellaneous costs. We also receive monthly incentives if we meet defined stripped coal reserves, ash quality or heating quality targets and an annual incentive for meeting defined reclamation targets. The contract includes an obligation to purchase a minimum of 2.3 million tons of coal through the expiration date of December 31, 2026.
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. We have separate agreements with the customer for each active pit. Payments are based on a fixed-base price per ton delivered for each contract adjusted annually for changes in actual costs and indices, plus reimbursements for royalties, lease payments, and other miscellaneous costs. We also receive a fixed monthly payment regardless of tons delivered during the period. The contracts include a combined obligation to purchase a minimum of 2.2 million tons of coal each year through the expiration date of December 31, 2026.
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, consisting of a single shipment or a series of shipments over the course of a year. Individual contracts are negotiated, generally based on prevailing Newcastle

14

pricing, with forward pricing of tons locked at a discount and adjustments to the agreed upon fixed-base price based on differences in calorific content from expectations.
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 75,000 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 active mining complexes in Ohio comprising thirteen surface mines.
The Ohio operations include a river terminal on the Ohio River, two washing facilities, two rail loadout facilities and a tipple facility. The mines are a combination of area, contour, auger and highwall mining methods using truck/shovel and truck/loader equipment along with large production 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. As of December 31, 2017, WMLP had in place leases or subleases to others for approximately 16.6 million tons of the total reserves owned or controlled by WMLP. We believe that WMLP has satisfied all lease conditions in order to retain the properties and keep the leases in place.
Coal - WMLP Segment Customers
In 2017, WMLP derived approximately 67% of its revenues from coal sales to three customers: Pacificorp Energy, Inc. (34%), AEP (23%) and East Kentucky Power Cooperative (10%). WMLP sells the majority of its tons under contracts with a weighted average remaining supply obligation term of approximately four years.
Ohio Operations. The Ohio operations supply coal under long-term supply contracts to two significant customers, AEP and East Kentucky Power Cooperative. The AEP contract has an expiration date of December 31, 2018 and payments are based on a fixed-base price per ton of coal to be delivered with adjustments based on quality measurements. The customer has an obligation to purchase a minimum of 750 thousand tons in 2018. There are multiple contracts with EKPC that have expiration dates ranging from March 31, 2019 to December 31, 2020. Payments under these contracts are based on a fixed-base price per ton of coal to be delivered with adjustments based on quality measurements. The customer has an obligation to purchase a minimum of 840 thousand tons, 480 thousand tons, and 360 thousand tons in 2018, 2019, and 2020, respectively.
In addition to these agreements, the Ohio operations provide coal to various other customers under spot or short-term contracts generally based on prevailing market prices.
Kemmerer. The Kemmerer mine supplies the adjacent Naughton Power Station owned and operated by Pacificorp Energy, Inc. via conveyor belt under an agreement that expires on December 31, 2021. Prices under the coal supply agreement include a fixed-base price per ton delivered for set minimum quantities each contract year and a lower fixed-base price per ton delivered for optional tons in excess of stated minimums. These fixed-base prices are adjusted quarterly based on changes in various cost and commodity indices. Naughton Power Station’s Unit 3 is scheduled to be shutdown at the beginning of 2019. The customer has an obligation to purchase a minimum of 2.2 million tons in 2018, 1.7 million tons in 2019, and 1.4 million tons in 2020 and 2021, respectively.
The Kemmerer mine also supplies various industrial customers including Genesis Alkali (formerly Tronox Alkali - Green River and Grainger) and Tata Chemicals North America Inc. through contracts with expiration dates ranging from December 31, 2019 to December 31, 2026. These industrial customers are supplied via Union Pacific rail and truck. Prices under the supply agreements are fixed-base costs with periodic adjustments based on certain inflation/commodity indices.
Competition

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The North American coal industry is intensely competitive. In addition to competition from other coal producers, we compete with producers of alternative fuels used for electrical power generation, such as nuclear energy, natural gas, hydropower, petroleum, solar and wind. Costs and other factors such as safety, environmental and regulatory considerations relating to alternative fuels affect the overall demand for coal as a fuel.
The majority of the mines in our Coal - U.S. and Coal - Canada segments, as well as our Kemmerer mine in the Coal - WMLP segment, focus on 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. WMLP's principal direct competitors are other coal producers, including but not limited to (listed alphabetically) Alliance Resource Partners, L.P., Alpha Natural Resources, CONSOL Energy, Foresight Energy, Hallador Energy Company, Murray Energy Corporation, Peabody Energy Corp., Rhino Resource Partners, L.P. and various other smaller, independent producers.
Washing Facilities
Depending on coal quality and customer requirements, some raw/crushed coal may be shipped directly from the mine to the customer. However, the quality of some raw coal does not allow direct shipment to the customer without putting the coal through a washing process that physically separates impurities from the coal. This processing upgrades the quality and heating value of the coal by generally removing ash, but it entails additional expense and results in some loss of coal. The Company owns and operates four washing facilities as follows:

•
Strasburg (Strasburg, Ohio): Throughput capacity of 250 tons of raw coal per hour and operated at a 44.5% utilization rate in 2017.
•
Conesville (Coshocton County, Ohio): The wash plant was idled throughout 2017 due to poor market conditions. This facility is adjacent to a customer’s power plant.
•
Buckingham (Corning, OH): Throughput capacity of 700 tons of raw coal per hour and operated at a 98.7% utilization rate in 2017.
•
Coal Valley (Edson, Alberta): Throughput capacity of 1,160 tons of raw coal per hour and operated at a 85.0% utilization rate in 2017.
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. However, certain of our operations, most specifically our Coal Valley mine and Ohio operations, have exposure to seasonal transportation limitations.

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Power Segment

Prior to the fourth quarter sale of substantially all of the assets and liabilities in the segment, as well as the termination of all related power agreements, we owned 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 was held by our wholly-owned subsidiary Westmoreland Partners. All of the tangible and intangible assets of Westmoreland Partners were encumbered by liens securing our 8.75% Notes and Term Loan.

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. At this point, Westmoreland Partners was no longer obligated to operate ROVA in order to fulfill its contracted energy and capacity requirements. Under the Amending Agreement, Westmoreland Partners continued to mitigate its cash losses from generation through the sale to DNCP of substitute power not produced by ROVA. Further, we were required to post collateral to cover certain projected long-term losses under these hedging arrangements based on the market price for power.

As we were 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. The asset group was 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 on the Consolidated Statements 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, WRMI, through which we have elected to retain some of our operating risks. WRMI 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"), 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 performance at our mines was as follows:

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2017
 
2016
 
Reportable Rate
 
Lost Time Rate
 
Reportable Rate
 
Lost Time Rate
U.S. Surface Operations
1.45
 
0.89
 
1.34
 
0.70
U.S. National Surface Average
1.35
 
0.78
 
1.44
 
0.96
Percentage
107%
 
114%
 
93%
 
73%
 
 
 
 
 
 
 
 
U.S. Underground Operations
1.55
 
0.97
 
3.23
 
2.09
U.S. National Underground Average
4.86
 
3.78
 
4.95
 
3.56
Percentage
32%
 
26%
 
65%
 
59%
 
 
 
 
 
 
 
 
Canadian Operations
1.49
 
0.41
 
2.82
 
0.89
Regulations
We are subject to extensive regulation with respect to environmental and other matters by federal, state, provincial and local authorities in both the United States and Canada. Regulations to which we are subject include, but are not limited to, the following:
U.S. Federal Law and Regulations
 
Canadian Provincial Law and 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 Law and 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
 
  The Water Security Agency Act
 
 
Various other climate change laws and initiatives
Federal, tribal, state, and local authorities regulate the U.S. coal mining industry with respect to numerous matters, such as protection of air quality, water quality, wetlands, special status species of plants and animals, land uses, cultural and historic properties, and other environmental resources. These laws and regulations have, and will continue to have, a significant adverse effect on the production and competitive position of the coal industry as against other energy sources. We endeavor to conduct our operations in compliance with all applicable federal, state, and local laws and regulations. However, non-compliance with federal, tribal and state laws and regulations could subject us to material administrative, civil or criminal penalties or other liabilities, including suspension or termination of operations. In addition, we may be required to make large and unanticipated capital expenditures to comply with future laws, regulations or orders as well as future interpretations and more rigorous enforcement of existing laws, regulations or orders, the extent to which we cannot predict. Our reclamation obligations under applicable environmental laws will be substantial. Certain of our coal sales agreements contain government imposition provisions that allow the pass-through of compliance costs in some circumstances.
The following is a summary of various U.S. federal laws and regulations that have a material impact on our business:
U.S. Regulation    

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The change in U.S. Presidential Administration in 2017 has resulted in a number of executive branch initiatives, some of which are discussed below, seeking to reverse the prior Administration’s economic, environmental, and energy-related policies. Because of the uncertainty associated with these initiatives and pending or anticipated legal challenges by states, environmental groups, individuals, and others, we cannot predict the ultimate impact of the current Administration’s initiatives on our businesses.
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 the appropriate state agency if it has obtained regulatory primacy. A state agency may achieve primacy if it develops a mining regulatory program that is no less stringent than the equivalent federal mining regulatory program under SMCRA. All states in which we conduct mining operations have achieved primacy and issue permits in lieu of the OSM. SMCRA permit provisions include a complex set of requirements that include, among other things, coal prospecting, mine plan development, topsoil or growth medium removal and replacement, handling of overburden materials, mine pit backfilling and grading, disposal of excess spoil, protection of the hydrologic balance, surface runoff and drainage control, establishment of suitable post mining land uses, and re-vegetation. Permitting under SMCRA and its state analogs has generally become more difficult in recent years. This difficulty in permitting affects the availability of coal reserves at our coal mines.
Under federal and state laws, a mine operator must also assure, usually through the use of surety bonds, payment of certain long-term obligations, including the costs of mine closure and reclamation of 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 11 - Asset Retirement Obligations to the consolidated financial statements for the amount of surety bonds posted and cash collateral securing these bonds for reclamation purposes. In addition to the bond requirement, the Abandoned Mine Land Fund-created by SMCRA-imposes a fee on all coal produced. The proceeds of the fee are used to restore mines closed or abandoned prior to SMCRA’s adoption in 1977. The current fee is $0.28 per ton of coal produced from surface mines. In 2017, we recorded $5.3 million of expense related to this reclamation fee.
In January 2016, the Department of Interior’s Bureau of Land Management announced a moratorium on new coal leases on federal lands. On March 28, 2017, President Trump issued an Executive Order on Promoting Energy Independence and Economic Growth (“EI Order”), which mandated the lifting of the moratorium. On March 29, 2017, the Interior Secretary issued Order 3348, terminating the federal coal-leasing moratorium.
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. On November 17, 2017, the OSM published notice in the Federal Register that it removed the text of the Stream Protection Rule from the Code of Federal Regulations and restored the text of the regulations to that as it appeared on January 18, 2017. The regulations now in effect are those that were in place on January 18, 2017.
It is our policy to comply in all material respects with the requirements of the SMCRA and the state and tribal laws and regulations governing mine reclamation.
Clean Air Act (“CAA”) and Related Regulations. The CAA and comparable state laws that regulate air emissions affect coal mining operations both directly and indirectly. Direct impacts on coal mining and processing operations include CAA permitting requirements and emission control requirements relating to air pollutants, including particulate matter, which may include controlling fugitive dust. Indirect impacts on coal mining operations include emissions regulations for particulate matter, sulfur dioxide, nitrogen oxides, mercury and other compounds emitted by coal-fired power plants. The air emissions programs, regulatory initiatives and standards that may affect our operations, directly or indirectly, include, but are not limited to, the following:
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Greenhouse Gas (“GHG”) Emissions Standards. In August 2015, the EPA finalized standards for greenhouse gases for new, modified, or reconstructed electric generating units ("EGUs") referred to as “new source performance standards” ("NSPS"). The final NSPS for coal-fired EGUs, promulgated pursuant to Section 111(b) of the CAA, require, in most cases, the installation of partial carbon capture and sequestration at new, modified, or reconstructed coal-fired EGUs, 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 U.S. Court of Appeals for the D.C. Circuit.

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However, on March 28, 2017, EPA filed a motion, pursuant to President Trump’s March 28, 2017 EI Order, requesting that the consolidated cases be held in abeyance pending completion of EPA’s review of the rule and any forthcoming rulemaking. On August 10, 2017, the D.C. Circuit granted the motion, holding the cases in abeyance and requiring that EPA submit regular status reports. The EPA’s most recent status report indicates that “[a]t this time, EPA continues to review the 111(b) Rule, as required under the Executive Order.” (D.C. Cir. No. 15-1381; Jan. 25, 2018).

Existing coal-fired EGUs were also going to be subject to GHG performance standards. The new standards were set to reduce GHG emissions from the power sector by 32% from 2005 levels by 2030. The “Clean Power Plan,” promulgated pursuant to Section 111(d) of the CAA, would impose stringent standards on existing fossil fuel-fired EGUs that reflect the EPA’s assessment of the “best system of emission reduction” ("BSER"). These existing source standards are implemented by the states, requiring that they meet individual GHG emission “goals” beginning in 2022 with phased reductions through 2030. The final goals have a greater impact on states with substantial coal-fired generation; Wyoming, for example, would be 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 be requested. 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 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. On March 28, 2017, however, the EPA moved to hold the consolidated cases in abeyance pending its reconsideration of the Clean Power Plan, pursuant to President Trump’s March 28, 2017 EI Order. On April 28, 2017, the D.C. Circuit granted the motion and required the EPA to file regular status reports. The EPA’s most recent status report indicates that on October 10, 2017, the EPA “Administrator signed a Federal Register notice proposing to repeal the Clean Power Plan on the grounds that it exceeds EPA’s statutory authority under a proposed change in the Agency’s interpretation of section 111 of the [CAA].” (D.C. Cir. No. 15-1363 Feb. 9, 2018). On March 1, 2018, the court ordered that the consolidated cases remain in abeyance.

Any final rule promulgated by the Trump Administration regarding GHG emission standards will be subject to judicial review. As such, it is unclear whether the appellate process regarding NSPS or the Clean Power Plan will continue. If either rule is upheld in its current form, it is likely that demand for coal will decrease and adversely impact our business.

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Mercury & Air Toxics Standards. In February 2012, the EPA published national emission standards under Sections 111 and 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 generally requires 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 2015, the U.S. Supreme Court held that the EPA had failed to properly consider costs when assessing whether to regulate fossil fuel-fired EGUs under the hazardous air pollutant provisions of the Clean Air Act, referring to the agency’s own estimate that the rule would cost power plants nearly $10 billion per year. The D.C. Circuit remanded the rule to the EPA to conduct a cost assessment but without vacatur, allowing the rule to remain in effect while the EPA conducted the rulemaking. On December 1, 2015, the EPA published a proposed supplemental finding that regulation of EGUs is still “appropriate and necessary” in light of the costs to regulate hazardous air pollutant emissions from the source category. On April 14, 2016, the EPA issued a final rule confirming its “appropriate and necessary” finding to regulate air toxics, including mercury, from power plants after considering costs. The final rule was immediately challenged by several states, companies, and industry groups. Several states and environmental groups also filed as intervenors for the respondent EPA. On April 27, 2017, the D.C. Circuit issued an order holding the consolidated cases in abeyance and directing the EPA to file status reports on the agency’s review of the supplementing finding every ninety days. The EPA’s most recent status report indicates that the “EPA is continuing to review the Supplement Finding to determine whether the rule should be maintained, modified, or otherwise reconsidered.” (D.C. Cir. No. 16-1127; Jan. 19, 2018).

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National Ambient Air Quality Standards (“NAAQS”) for Criteria Pollutants. The CAA requires the EPA to set standards, referred to as NAAQS, for certain pollutants associated with the combustion of coal, such as nitrogen dioxide particulate matter, ozone, and sulfur dioxide. Areas that are not in compliance (referred to as non-

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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. If our customers are located in non-attainment areas or areas that become non-attainment areas, they may also be forced to modify their operations. 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 (“2015 Rule”). Several industry and business groups, five states, and Murray Energy Corp. challenged the revised standard in the D.C. Circuit. On April 11, 2017, the D.C. Circuit granted EPA’s petition to indefinitely delay oral arguments in the litigation while the agency reviewed the rule. The D.C. Circuit directed EPA to file status reports on the agency’s review of the 2015 Rule every ninety days. EPA’s most recent status report indicates that it is “continuing to review the 2015 Rule to determine whether the standards should be maintained, modified, or otherwise reconsidered.” (D.C. Cir. No. 15-1385 Jan. 8, 2018).

In a separate lawsuit, a coalition of states and environmental organizations recently challenged the EPA to finalize initial area air quality designations under the 2015 ozone standards. On March 12, 2018, the U.S. District Court for the Northern District of California ruled that the EPA has until April 30, 2018, to finalize the standards for all areas of the country except for the San Antonio, Texas area (which must be finalized prior to July 17, 2018). (N.D. Cal. 4:17-cv-06900 Mar. 12, 2018).

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Other Programs. A number of other air-related programs may affect the demand for coal and, in some instances, coal mining directly by regulating air emissions emitted by coal-fired EGUs. These include, but are not limited to, the Acid Rain Program, interstate transport rules such as the Cross-State Air Pollution Rule, the Regional Haze Program, and requirements related to New Source Review.
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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. This restricts our ability to sell coal to power plants that do not utilize sulfur dioxide emission controls and otherwise leads to a price discount based, in part, on the market price for sulfur dioxide emission allowances under the Clean Air Act. Our coal also contains about fifty percent more ash content than our primary competitors, which can translate into a cost disadvantage where post-combustion coal ash must be land filled.
Clean Water Act. The Clean Water Act (“CWA”) and corresponding state and local laws and regulations affect coal mining and power generation operations by restricting the discharge of pollutants, including dredged or fill materials, into “waters of the United States.” Under the National Pollutants Discharge Elimination System (“NPDES”) and delegated state permitting systems, any discharge of pollutants from a point source into a “water of the United States” requires a discharge permit from the EPA or the state. Additionally, state and local governments regulate nonpoint source pollution through a number of regulatory programs. Under both point source and nonpoint source programs, issuance of permits with more stringent terms and conditions may increase compliance costs for us and our customers.
In January 2017, the U.S. Army Corps of Engineers (the "Corps") issued general nationwide permits for specific activities requiring authorization under Section 404 of the CWA and Section 10 of the Rivers and Harbors Act of 1899. The nationwide permits cover activities that are similar in nature and that are determined to have minimal adverse environmental effects. The permits became 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.

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 Corps jointly issued a final rule defining “waters of the United States” (“WOTUS Rule”) to clarify which waters and wetlands are subject to regulation under the CWA. Implementation of the WOTUS Rule was stayed nationwide in October 2015, and on February 6, 2018, the EPA published in the Federal Register a rule delaying implementation of the WOTUS Rule by two years (through February 6, 2020). States and environmental organizations are currently challenging the February 6, 2018 rule. Continued court challenges and regulatory actions create ongoing uncertainty over CWA jurisdiction and permitting requirements, which could either increase or decrease the cost and time spent on CWA compliance. New reporting requirements and pending litigation associated with coal combustion residuals may cause power generation customers to face increased costs in complying with the CWA, which could impact demand for our products. Finally, in light of real or perceived efforts toward federal deregulation, the prospect of citizen suits to enforce certain provisions of the CWA may increase, which could result in greater regulatory and litigation costs.

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Endangered Species Act. The Federal Endangered Species Act (“ESA”), and similar state laws, protect any species listed as threatened with extinction and protect their critical habitat. The U.S. Fish and Wildlife Service (“FWS”) works with the OSM and state agencies to administer the ESA and ensures that species subject to its provisions are protected from mining-related impacts. Protection of endangered and threatened species may cause us to modify mining plans or develop and implement species-specific protection and enhancement plans to avoid or minimize impacts to endangered species or their habitats. A number of species indigenous to the areas where we operate are protected under the ESA and equivalent state laws and regulations. Species in the vicinity of our operations may have their listing status reviewed in the future, however, at this time, we do not believe any of these species protections under the ESA or similar state laws will have a materially adverse effect on our ability to mine coal from our properties.

Resource Conservation and Recovery Act. We may generate wastes, including “solid” wastes and “hazardous” wastes, that are subject to the federal Resource Conservation and Recovery Act (“RCRA”), and comparable state statutes, although certain mining and mineral beneficiation wastes and certain wastes derived from the combustion of coal currently are exempt from regulation as hazardous wastes under RCRA. The EPA has limited the disposal options for certain wastes that are designated as hazardous wastes under RCRA. Furthermore, it is possible that certain wastes generated by our operations that currently are exempt from regulation as hazardous wastes may in the future be designated as hazardous wastes, and therefore be subject to more rigorous and costly management, disposal and clean-up requirements.

The EPA determined that coal combustion residuals (“CCR”) do not warrant regulation as hazardous wastes under RCRA in May 2000. Most state hazardous waste laws do not regulate CCR as hazardous wastes. The EPA also concluded that beneficial uses of CCR, other than for mine filling, pose no significant risk and no additional national regulations of such beneficial uses are needed. However, the EPA determined that national non-hazardous waste regulations under RCRA are warranted for certain wastes generated from coal combustion, such as coal ash, when the wastes are disposed of in surface impoundments or landfills or used as minefill. EPA Administrator Gina McCarthy signed the final rule relating to the disposal of CCR from electric utilities on December 19, 2014, which was published in the Federal Register on April 17, 2015 ("CCR Rule"). The CCR Rule regulates CCR as 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. The CCR Rule is largely silent on the reuse of coal ash. In August 2017, EPA released interim final guidance to be used by states developing their own State CCR Permit Programs, under which states may, but are not required to, develop and submit CCR permit programs to EPA for approval. On March 1, 2018, EPA Administrator Scott Pruitt issued a pre-publication version of a proposed rule that would amend the CCR Rule. Among other changes, the proposed revisions would allow states or EPA the ability to incorporate flexibilities into their coal ash permit programs.
Continued changes in the management of CCR could increase both our and our customers’ operating costs and potentially impact 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, joint and several liability covering 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. Although the EPA excludes most wastes generated by coal mining and processing operations from the hazardous waste laws, such wastes can, in certain circumstances, constitutes hazardous substances for the purposes of CERCLA. In addition, the disposal, release, or spilling of some products used by coal companies in operations, such as chemicals, could trigger the liability provisions of the statute. Thus, coal mines that we currently own or operate, coal mines that we have previously owned or operated, and sites to which we have sent waste materials, may be subject to liability under CERCLA and similar state laws. 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.
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

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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 United States 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. However, as discussed above, most of these regulations are currently subject to judicial review pending the Trump Administration’s review. Demand for coal may also be impacted by international efforts to reduce emissions of greenhouse gases. At this time, the extent to which the United States will participate in international climate change initiatives is unknown.
The impact of GHG-related legislation and regulations on our business, including a “cap and trade” structure, 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 or international initiatives 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 initiatives, 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.
We are required to comply with numerous other federal, state, and local environmental laws and regulations in addition to those previously discussed. Such additional laws include, for example, the Emergency Planning and Community Right-to-Know Act, the Toxic Substance Control Act, the Migratory Bird Treaty Act, and the Safe Drinking Water Act.
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:
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.

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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 Water Security Agency Act. Similar to the Water Act in Alberta, The Water Security Agency Act in Saskatchewan 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 this legislation, a corporation conducting an activity without the requisite approval or in contravention of the specific terms and conditions of an authorization is liable to a fine and/or administrative penalty, which may have a material adverse effect on our business.
The Crown Minerals Act. Similar to the MM Act in Alberta, the Crown Minerals Act (the “CM Act”), and its underlying regulations, governs the management and disposition of rights in Crown owned mines and minerals. The Saskatchewan Ministry of Economy administers the CM Act and the issuance of dispositions authorizing the exploration and development of coal resources in the province. Contravention of the terms of a Crown disposition or the provisions of the CM Act may result in cancellation of that disposition and/or financial penalties, both of which may have a material adverse effect on our business.
The Ecological Reserves Act. The Ecological Reserves Act (the “ER Act”) protects unique, natural ecosystems and landscape features in Saskatchewan through the designation of Crown land as ecological reserves. Under the ER Act, the Lieutenant Governor in Council may make regulations and orders designating any Crown land as an ecological reserve, enlarging any ecological reserve, and restricting the activities which may be carried out on an existing ecological reserve. Designation of either of our Saskatchewan mine properties as an ecological reserve may restrict our mining activities on those properties, or cause us to modify mining plans; however, we do not have any reason to believe that either of our Saskatchewan properties are at risk of being designated an ecological reserve at this time.

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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). 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.

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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 increased 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 CCI 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 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 Carbon Competitiveness Incentive Regulation (the “CCI Regulation) (which effective January 1, 2018 replaces the former Specified Gas Emitters Regulation) requires a reduction in GHG emissions intensity for certain large GHG emitting facilities in Alberta.

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This system features emissions trading between regulated facilities and allows the use of offsets generated by projects in Alberta. Generally, the CCI Regulation establishes that companies emitting more than 100,000 tonnes 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 CCI Regulation. The CCI Regulation is applicable to the Coal Valley mine and also the power plants that are our customers.
In 2016 the Canadian federal government announced its Pan-Canadian Framework on Clean Growth and Climate Change (the "Pan-Canadian Framework") that indicated that it will speed up plans to phase out Canadian coal-fired electricity by 2030. Subsequently, the Saskatchewan and Canadian 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. The Saskatchewan government introduced its Prairie Resilience: A Made-in-Saskatchewan Climate Change Strategy (the “Saskatchewan Strategy”) in December 2017. The Saskatchewan Strategy includes principles of reducing GHG emissions without a carbon tax, and using coal in a responsible manner beyond 2030. A final equivalency agreement between the Saskatchewan and Canadian federal governments has not yet been completed. 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 included in the Pan-Canadian Framework, the Canadian federal government announced that they would 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. There is no legislation related to this announcement in place for January 1, 2018. Although there is no bill currently before the legislature related to this announcement, draft legislative and regulatory proposals were released in January 2018 for comments.
Future Canadian 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 (855) 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 Relating to our Capital Structure

We may seek protection from our creditors under Chapter 11 of the United States Bankruptcy Code ("Chapter 11") or an involuntary petition for bankruptcy may be filed against us, either of which could have a material adverse impact on our business, financial condition, results of operations, and cash flows and could place our shareholders at significant risk of losing all of their investment in our shares.

We have engaged financial and legal advisors to assist us in, among other things, analyzing various strategic alternatives to address our liquidity and capital structure, including strategic and refinancing alternatives to restructure our indebtedness in private transactions. However, if our attempts are unsuccessful or we are unable to complete such a restructuring on satisfactory terms, we may choose to pursue a filing under Chapter 11.
Seeking bankruptcy court protection could have a material adverse effect on our business, financial condition, results of operations and liquidity. For as long as a Chapter 11 proceeding continued, our senior management would be required to spend a significant amount of time and effort dealing with the reorganization as well as focusing on our business operations. Bankruptcy court protection also could make it more difficult to retain management and other key personnel necessary to the success of our business. In addition, during the period of time we are involved in a bankruptcy proceeding, our customers and suppliers might lose confidence in our ability to reorganize our business successfully and could seek to establish alternative commercial relationships, which may cause, among other things:
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third parties to lose confidence in our ability to deliver coal on time and at specification, resulting in a significant decline in our revenues, profitability and cash flow;
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difficulty retaining, attracting or replacing key employees;
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employees to be distracted from performance of their duties or more easily attracted to other career opportunities; and
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our suppliers, vendors, hedge counterparties and service providers to renegotiate the terms of our agreements, terminate their relationship with us or require financial assurances from us.

Additionally, all of our indebtedness is senior to the existing common stock in our capital structure. As a result, we believe that seeking bankruptcy court protection under a Chapter 11 proceeding could cause the shares of our existing common stock to be canceled, resulting in a limited recovery, if any, for shareholders of our common stock, and would place shareholders of our common stock at significant risk of losing all of their investment in our shares.
The audit report we received with respect to our year-end 2017 consolidated financial statements contains an explanatory paragraph referencing our conclusion (in Note 1 - Summary of Significant Accounting Policies to the consolidated financial statements) that substantial doubt exists as to our ability to continue as a “going concern.” The Revolver requires us to deliver audited, consolidated and consolidating financial statements with an unqualified opinion of our independent registered public accounting firm, as well as other financial covenant compliance reporting. We entered into the Thirteenth Amendment (as defined below) to the Revolver agreement waiving any such potential defaults. However, our failure in the future to obtain similar relief, if necessary, from reporting and financial covenant compliance requirements under the Revolver could result in an acceleration of all of our outstanding debt obligations.
Under the Revolver, we are required to deliver audited, consolidated and consolidating financial statements with an unqualified opinion of our independent registered public accounting firm, as well as other financial covenant compliance reporting. The audit report prepared by our independent registered public accounting firm, with respect to the financial statements in this Annual Report on Form 10-K, includes an explanatory paragraph referencing our conclusion that substantial doubt exists as to our ability to continue as a “going concern.” On March 30, 2018, we entered into the Consent, Joinder and Thirteenth Amendment to the Revolver ("Thirteenth Amendment"), with our Revolver lenders that waived any such default arising out of the delivery of the audit report prepared by our independent registered public accounting firm, with respect to the financial statements in this Annual Report on Form 10-K, containing such a going concern explanatory paragraph, together with certain other potential reporting and financial covenant defaults. For additional information regarding the Thirteenth Amendment, please see further detail in Item 9B - Other Information.

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If an event of default occurs under the Revolver, the lenders could declare the outstanding principal of our debt under the Revolver, together with accrued interest, to be immediately due and payable. In addition, if the lenders under the Revolver accelerate the loans outstanding under the Revolver, there will also be cross-defaults under the indenture related to our 8.75% Notes, which would in turn cross-default the Term Loan credit agreement. If these cross-defaults occurred, our outstanding indebtedness under these senior debt agreements would automatically accelerate.
If all of our outstanding senior indebtedness accelerates, we do not currently have sufficient liquidity to repay such indebtedness and would need additional sources of capital to do so. We could attempt to obtain additional sources of capital from asset sales, public or private issuances of debt, equity or equity-linked securities, debt for equity swaps, or any combination thereof. However, we cannot provide any assurances that we will be successful in obtaining capital from such transactions on acceptable terms, or at all, and if we fail to obtain sufficient additional capital to repay the outstanding indebtedness and provide sufficient liquidity to meet our operating needs, it may be necessary for us to seek protection from creditors under Chapter 11.
We own a controlling interest in WMLP, which qualifies it as a significant subsidiary under our 8.75% Notes indenture, and if indebtedness of greater than $25.0 million is accelerated at WMLP it would cause cross default under the 8.75% Notes indenture, the Term Loan credit agreement, the Revolver agreement and the San Juan Loan agreement.

Because we own approximately 93.94% of the outstanding equity in WMLP (as of December 31, 2017) it is considered a significant subsidiary under the 8.75% Notes indenture. If WMLP defaults on the WMLP Term Loan, and the lenders under that agreement accelerate the indebtedness thereunder in an amount greater than $25.0 million, it would be considered an event of default for our 8.75% Notes. The event of default under our 8.75% Notes would in turn cross-default our Term Loan and Revolver. WMLP recently entered into an agreement with its lenders under the WMLP Term Loan to waive any actual or potential default related to a failure to have certain cash management accounts subject to cash management agreements, or a failure to deliver an unqualified audit opinion (and without an explanatory paragraph referencing WMLP’s conclusion that substantial doubt exists as to its ability to continue as a “going concern”) in connection with delivery of its fiscal year 2017 financial statements, through May 15th, 2018. WMLP's failure to obtain permanent relief from its requirement to deliver an unqualified audit opinion in connection with delivery of its fiscal year 2017 financial statement could result in an acceleration of all of our outstanding debt obligations.

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, 2017, we had a total outstanding indebtedness of approximately $1,076 million as detailed in Note 8 - Debt And Lines Of Credit to the consolidated financial statements. Our substantial amount of indebtedness could have important consequences. For example, it could:
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increase our vulnerability to adverse economic, industry or competitive developments;
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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;
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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;
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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;
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increase our cost of borrowing;
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restrict us from making strategic acquisitions or causing us to make non-strategic divestitures;
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limit our ability to service our indebtedness, including the 8.75% Notes, the Term Loan, San Juan Loan and the Revolver;
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limit our ability to obtain additional financing for working capital, capital expenditures, debt service requirements, acquisitions and general corporate or other purposes;
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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
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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.

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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 Westmoreland Resources GP, LLC, the general partner of WMLP, WMLP entered into the WMLP Term Loan to refinance it’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 are obligors under the WMLP Term Loan and the loan will be non-recourse to Westmoreland and its wholly owned subsidiaries' assets. However, an acceleration of indebtedness greater than $25.0 million at WMLP would cause cross default of the 8.75% Notes, the Term Loan and the Revolver. If we further increase our indebtedness, the related risks that we now face, including those described above, could intensify.
If we fail to comply with certain covenants in our various debt arrangements it could cross-default other senior debt agreements within our capital structure, as well as 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. 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. Breaches of the Revolver financial covenants would cause a cross-default of the 8.75% Notes and the Term Loan. After the effects of the Thirteenth Amendment, we are in compliance with the financial covenants for the year ended December 31, 2017, however, we cannot assure future compliance with the financial covenants contained in our senior debt agreements detailed herein.

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, restructure or 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

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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.

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, 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 Units 1 & 2, and vacated the EPA's Best Available Retrofit Technology ("BART") analysis and remanded it to the EPA for further proceedings. The EPA has not yet taken action on a new regional haze plan as a result of the Ninth Circuit's decision. 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, PacifiCorp Energy Inc., 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 the Naughton Power Station to 100% natural gas fueling. Instead, the owner has stated that it intends to retire Unit 3 at the Naughton Power Station at the end of 2018. This retirement will result in the loss of coal sales at our Kemmerer mine, however, price protections built into the contract that are in effect until 2021 will partially offset the effects of a lower sales 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, and on February 6, 2018, the EPA published in the Federal Register a rule delaying implementation of the rule by two years (through February 6, 2020).
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, though pending proposals would amend the final rule. 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.  On November 17, 2017, the OSM published notice in the Federal Register that it removed the text of the Stream Protection Rule from the Code of Federal Regulations and restored the text of the regulations to how it appeared on January 18, 2017. The regulations now in effect are those that were in place on January 18, 2017.
We are also affected by Canadian GHG emissions regulations. On September 12, 2012, the federal government of Canada released final regulations for reducing GHG emissions from coal-fired electricity generation: “Reduction of Carbon Dioxide Emissions from Coal-Fired Generation of Electricity” (the “Canadian CO2 Regulations”). The Canadian CO2 Regulations required certain Canadian coal-fired electricity generating plants, effective July 1, 2015, to achieve an average

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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.
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 2017, our Coal - U.S. segment derived approximately 83% of its total revenues from coal sales to four customers: Public Service Company of New Mexico (36%), Colstrip Units 3&4 (24%), Colstrip Units 1&2 (12%) and AEP (11%). Our Coal - Canada segment derived approximately 86% of its total revenues from coal sales to three customers: SaskPower (44%), Trafigura Pte. Ltd. (26%) and ATCO Power (16%). Our Coal - WMLP segment derived approximately 67% of its total coal revenues from sales to three customers: Pacificorp Energy, Inc. (34%), AEP (23%) 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 to fuel the Sherburne County Station in Minnesota have historically been three-year rolling contracts, and as of December 31, 2017, we have contracted tons through 2018 with one owner and through 2019 with another owner. 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 we have been notified that 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 of our 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. 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.
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 meet its obligations as they become due and, in turn, would negatively affect our consolidated results.

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Our Buckingham and San Juan mines may subject us to increased regulation and risks associated with underground mining.
Our 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 underground mining operations subject us to increased regulatory scrutiny and increased costs of regulatory compliance.
Our ability to collect payments from our customers could be impaired if their creditworthiness deteriorates.
Our ability to receive payment for coal sold and delivered depends on the continued creditworthiness of our customers. If we determine that a customer is not creditworthy, we may not be required to deliver coal under the customer’s coal sales contract. If this occurs, we may decide to sell the customer’s coal on the spot market, which may be at prices lower than the contracted price, or we may be unable to sell the coal at all. Furthermore, the bankruptcy of any of our customers could materially and adversely affect our financial position. In addition, competition with other coal suppliers could cause us to extend credit to customers and on terms that could increase the risk of payment default.
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 pension plan obligations and assets, or the funded status of the pension 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 pension plan funding, cause volatility in the net periodic benefit cost and increase our future funding requirements. See Note 10 - 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 $332.1 million, $18.2 million and $4.3 million, respectively, at December 31, 2017. 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 9 - 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.

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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, 2018, 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.
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:
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quality of the coal and the percentage of coal ultimately recoverable;
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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;
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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;
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economic assumptions, including assumptions as to foreign exchange rates and future commodity prices;
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assumptions concerning the timing for the development of the reserves; and
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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

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to expend greater amounts than anticipated.
We are subject to stringent reclamation and closure standards for our mining operations. We calculated the total estimated reclamation and mine-closing liabilities according to the guidance provided by GAAP and current industry practice. Estimates of our total reclamation and mine-closing liabilities are based upon permit requirements and our engineering expertise related to these requirements. If our estimates are incorrect, we could be required in future periods to spend materially different amounts on reclamation and mine-closing activities than we currently estimate. Likewise, if our customers, some of whom are contractually obligated to pay certain reclamation costs, default on the unfunded portion of their contractual obligations to pay for reclamation, we could be forced to make these expenditures ourselves and the cost of reclamation could exceed any amount we might recover in litigation.
See Note 11 - 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 require that applicants collateralize portions of their obligations to the bonding company. In 2017, we paid approximately $11.0 million in premiums and fees related to our reclamation bonds. If the bonding premium or collateral requirements increase, any cash that we provide to collateralize our obligations to our bonding companies is not available to support our other business activities and our results of operations could be negatively affected. 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, unprecedented rain at the Kemmerer mine, and unanticipated maintenance of certain 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 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

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plant ran at half its capacity until the necessary repairs were completed in early December 2015. We maintain business interruption insurance coverage at some of our mines to lessen the impact of events such as this. However, business interruption insurance may not always provide adequate compensation for lost coal sales, and significant unanticipated outages at our power plant customers which result in lost coal sales could result in significant adverse effects on our operating results. Additionally, our Beulah mine filed an intercompany business interruption claim with WRMI, 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's mines 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 through acquisition 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. 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, which did not occur in the fourth quarter of 2017 and we do not expect to occur again in the near future.

We previously expected our partnership interests in WMLP to be significant cash-generating assets, however, in the fourth quarter 2017 WMLP did not make a distribution as a result of failure to meet distribution covenants within the WMLP Term Loan Facility financing agreement. Our cash flow from WMLP's operations is dependent upon the ability of WMLP to make quarterly distributions to its unitholders, including us. If WMLP cannot regain compliance with its distribution covenants or it does not have sufficient available cash each quarter to enable it to pay distributions, it will continue to negatively impact us. Additionally, 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:

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restrictions contained in the debt agreements to which it is a party;
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the domestic and foreign supply and demand for coal;
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the quantity and quality of coal available from competitors;
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the prices under WMLP’s existing contracts where the pricing is tied to and adjusted periodically based on indices reflecting current market pricing;
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competition for production of electricity from non-coal sources, including the price and availability of alternative fuels;
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domestic air emission standards for coal-fueled power plants and the ability of coal-fueled power plants to meet these standards by installing scrubbers or other means;
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adverse weather, climate or other natural conditions, including natural disasters;
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domestic and foreign taxes;
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domestic and foreign economic conditions, including economic slowdowns;
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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;
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the proximity to, capacity of and cost of transportation and port facilities;
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market price fluctuations for sulfur dioxide emission allowances;
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the level of capital expenditures it makes;
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the cost of acquisitions;
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its debt service requirements and other liabilities;
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fluctuations in its working capital needs;
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its ability to borrow funds and access the capital markets; and
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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. Because of its distribution covenants, 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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Our deferred tax assets could be substantially limited if we experience an ownership change as defined in the Internal Revenue Code.
 
We have significant deferred tax assets related to net operating loss carryforwards and other tax benefits of WCC and its subsidiaries (collectively, the “Deferred Tax Assets”). Under federal tax laws, we can carry forward and use our Deferred Tax Assets to reduce our future taxable income and tax liabilities until such Deferred Tax Assets expire in accordance with the Internal Revenue Code of 1986, as amended (the “Code”). Section 382 and Section 383 of the Code provide an annual limitation on our ability to utilize our Deferred Tax Assets, as well as certain built-in-losses, against future taxable income in the event of a change in ownership (as defined under the Code). While we have adopted the Rights Plan to protect stockholder value by attempting to diminish the risk that the Company’s ability to use its Deferred Tax Assets (See Note 17. Income Tax to the consolidated financial statements for details) may become substantially limited, we could experience a change in ownership in the future as a result of changes in our stock ownership that are beyond our control, and any such subsequent changes in ownership for purposes of the Code could further limit our ability to use our Deferred Tax Assets. Accordingly, any such occurrences could adversely impact our ability to offset future tax liabilities and, therefore, adversely affect our financial condition, results of operations and cash flow.

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. 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:
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the interpretation and enforcement of contractual obligations between us and our affiliates, on the one hand, and WMLP, on the other hand; and

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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.
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 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. Certain states 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.

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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.
Certain of 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, 2017, approximately 60% of our total workforce is represented by three labor unions, the IUOE, the International Brotherhood of Electrical Workers and the UMWA. Our unionized workforce is spread out amongst the majority of our surface mines and our San Juan mine. 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 in light of recent Company disclosure regarding its ability to continue as a going concer, 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, settled at a relatively

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weak position during 2016 and recovered slightly in 2017. If the Canadian dollar remains weak in comparison to the U.S. dollar, earnings generated from our Canadian operations will translate into reduced earnings in the 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 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. However, implementation of this excise tax, which would impose a 40% excise tax on employers to the extent that the value of their healthcare plan coverage exceeds certain dollar thresholds, has been delayed until 2022. 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.

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 recent emergence from restructuring events of several North American coal producers may have strengthened their positions within the competitive markets in which we sell coal, the near and long-term effects of such on our competitive position is unclear.
Any change in consumption patterns by utilities away from the use of coal could affect our ability to sell the coal we produce or the prices that we receive.
In addition to competing with other coal producers, we compete generally with producers of other fuels. In 2017, 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. Though certain of our contracts contain take or pay provisions, only some of our contracts guarantee the purchase of fixed quantities of coal and, as a result, in certain economic environments revenue can fall despite these 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

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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:
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currency exchange rates;
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growth of economic development;
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price of alternative sources of electricity or steel;
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worldwide demand for coal and other sources of energy; and
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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:
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limitations on land use;
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employee health and safety;
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mandated benefits for retired coal miners;
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mine permitting and licensing requirements;
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reclamation and restoration of mining properties after mining is completed;
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air quality standards;
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discharges to water;
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construction and permitting of facilities required for mining operations, including valley fills and other structures constructed in water bodies and wetlands;
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protection of human health, plant life and wildlife;
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management of the materials generated by mining operations and discharge of these materials into the environment;
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effects of mining on groundwater quality and availability; and
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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

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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 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. On March 28, 2017, however, the EPA moved to hold the consolidated cases in abeyance pending its reconsideration of the Clean Power Plan, pursuant to President Trump’s March 28, 2017 EI Order. On April 28, 2017, the D.C. Circuit granted the motion and required the EPA to file regular status reports. The EPA’s most recent status report indicates that on October 10, 2017, the EPA “Administrator signed a Federal Register notice proposing to repeal the Clean Power Plan on the grounds that it exceeds EPA’s statutory authority under a proposed change in the Agency’s interpretation of section 111 of the [CAA].” (D.C. Cir. No. 15-1363; Feb. 9, 2018). On March 1, 2018, the court ordered that the consolidated cases remain in abeyance.
Any final rule promulgated by the Trump Administration regarding GHG emission standards will be subject to judicial review. As such, it is unclear whether the appellate process regarding NSPS or the Clean Power Plan will continue. If either rule is upheld in its current form, it is likely that demand for coal will decrease and adversely impact our business. 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 -

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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” (effective through December 31, 2017), which was replaced by the “Carbon Competitiveness Incentive Regulation” (effective January 1, 2018). 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 2016 compliance period, Coal Valley mine was not required to purchase fund credits. For the 2017 compliance period, the calculations indicate that the Coal Valley mine will be required to purchase fund credits. 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 10,000 tonnes or more of specified gases to report their annual 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 only limited sections have been proclaimed in force. The legislation provides a framework for the control of GHG emissions by regulated emitters and the remainder are expected to 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 legislation that would see costs of emissions to large emitters increase. The Government of Alberta took steps to implement some of the recommendations in the report including steps related to the shutdown of coal-fired power generation by the year 2030 and a carbon levy. The full effects of these actions of the Alberta Government, and any other new legislation, are unknown at this time. 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 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.

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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. 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.
Our customers are subject to extensive environmental regulations particularly with respect to air emissions other than GHG. Coal contains impurities, including but not limited to sulfur, mercury, chlorine and other elements or compounds, many of which are released into the air when coal is burned. The emission of these and other substances is extensively regulated at the federal, state, provincial and local level, and these regulations significantly affect our customers’ ability to use the coal we produce and, therefore, the demand for that coal. The EPA has issued a number of significant regulations to impose more stringent requirements relating to air, water and waste controls on electric generating units. For more details, see Item 1 - Business - Material Effects of Regulation.
Considerable uncertainty is associated with air emissions initiatives, and it is unclear how the Trump Administration will proceed with both its review of 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 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 Climate Change and Emissions Management Act, 2003 (“CCEM Act”) and the 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 CCEM Act 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/or address emissions limits exceedances, 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.

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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

Our failure to meet the continued listing requirements of The Nasdaq Global Market could result in a delisting of our common stock and make harder for shareholders to trade in our common stock.

Our common stock is listed on The Nasdaq Global Market, which imposes, among other requirements, a minimum bid price requirement and a minimum market value requirement. If the closing bid price for our common stock is less than $1.00 per share for 30 consecutive business days or the total market value of publicly held shares of the Company closes at less than $15 million for 30 consecutive business days, Nasdaq may send us a notice stating we will be provided a period of 180 days to regain compliance with these requirements or else Nasdaq may make a determination to delist our common stock. On March 22, 2018 our stock had traded for less than $1.00 for 30 consecutive business days, and we received notice of non-compliance from The Nasdaq Global Market. We have a 180 calendar day grace period, or until September 18, 2018, to regain compliance with the minimum bid price requirement. The continued listing standard will be met if our common stock has a minimum closing bid price of at least $1.00 per share for a minimum of 10 consecutive business days during the 180 calendar day grace period. On March 23, 2018 our common stock's market value for publicly held shares closed below $15 million for 30 consecutive business days, and we received a second notice of non-compliance from The Nasdaq Global Market. We have a 180 calendar day grace period, or until September 19, 2018, to regain compliance with the market value requirement. The continued listing standard will be met if our common stock has a total market value for publicly held shares at closing greater than $15 million for a minimum of 10 consecutive business days during the 180 calendar day grace period. The failure to meet either of these continuing compliance standards subjects our common stock to delisting.

The delisting of our common stock from Nasdaq may make it more difficult for us to raise capital on favorable terms in the future. Such a delisting would likely have a negative effect on the price of our common stock and would impair your ability to sell or purchase our common stock when you wish to do so. Further, if we were to be delisted from The Nasdaq Global Market, our common stock would cease to be recognized as covered securities and we would be subject to regulation in each state in which we offer our securities. There can be no assurance that we will be successful in regaining compliance. Moreover, there is no assurance that any actions that we take to restore our compliance with Nasdaq's listing requirements would stabilize the market price or improve the liquidity of our common stock, prevent our common stock from remaining below the Nasdaq minimum bid price or total market value required for continued listing or prevent future non-compliance with asdaq's listing requirements. Delisting may also result in our common stock trading on the over-the-counter market, which may be a less liquid market. In such case, our shareholders’ ability to trade, or obtain quotations of the market value of, shares of our common stock would be severely limited because of lower trading volumes and transaction delays. These factors could contribute to lower prices and larger spreads in the bid and ask prices for our securities.
 
In addition to the foregoing, if our common stock is delisted from Nasdaq and it trades on the over-the-counter market, the application of the “penny stock” rules could adversely affect the market price of our common stock and increase the transaction costs to sell those shares. The SEC has adopted regulations which generally define a “penny stock” as an equity security that has a market price of less than $5.00 per share, subject to specific exemptions. The last reported trade of our Company common stock on The Nasdaq Global Market was at a price below $5.00 per share. If our common stock is delisted from Nasdaq and it trades on the over-the-counter market at a price of less than $5.00 per share, our common stock would be considered a penny stock. The SEC’s penny stock rules require a broker-dealer, before a transaction in a penny stock not otherwise exempt from the rules, to deliver a standardized risk disclosure document that provides information about penny stocks and the risks in the penny stock market. The broker-dealer must also provide the customer with current bid and offer quotations for the penny stock, the compensation of the broker-dealer and the salesperson in the transaction, and monthly account statements showing the market value of each penny stock held in the customer’s account. In addition, the penny stock rules generally require that before a transaction in a penny stock occurs, the broker-dealer must make a special written determination that the penny stock is a suitable investment for the purchaser and receive the purchaser’s agreement to the transaction. If applicable in the future, these rules may restrict the ability of brokers-dealers to sell our common stock and may affect the ability of investors to sell their shares, until our common stock no longer is considered a penny stock.
Provisions of our certificate of incorporation, bylaws, Delaware law and our stockholder rights plan or "poison pill," 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.

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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. 
On September 2, 2017, the board of directors of the Company adopted a tax benefits preservation plan or stockholder rights plan (the "Rights Plan"). The purpose of the Rights Plan is to minimize the likelihood of an ownership change occurring for Section 382 purposes and thus protect the Company's ability to utilize its Deferred Tax Assets (as defined below) to offset future income. The Rights Plan is intended to act as a deterrent to any person or group acquiring “beneficial ownership” of 4.75% or more of the outstanding shares of the Company's common stock, par value $0.01 per share without the approval of the board of directors. The description and terms of the Rights (as defined below) applicable to the Rights Plan are set forth in the 382 Rights Agreement, dated as of September 5, 2017 (the “Rights Agreement”), by and between WCC and Broadridge Corporate Issuer Solutions, Inc., as Rights Agent.
Each of 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:
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failure to implement our strategy for the development of the acquired assets;
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unanticipated changes in commodity prices;
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unanticipated changes in applicable laws and regulations;
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retaining and obtaining required regulatory approvals, licenses and permits;
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operating risks inherent in our business; and
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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.
The owners of SJGS, San Juan’s primary customer, 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. in December 2017, the owners of SJGS closed units 2 and 3, and as such, the demand for coal produced by the San Juan mine will decrease significantly negatively impacting 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.

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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. On August 31, 2016 Judge Robert Junell issued a decision that (1) granted OSM’s motion for a voluntary remand back to the agency to conduct the required NEPA process as it relates to WEG’s claimed deficiencies, and (2) mandated that OSM and SJCC conduct an Environmental Impact Statement (“EIS”) to address the alleged deficiencies of the original NEPA process within a three year time frame at which time automatic vacatur of the mining permit would occur absent a showing of good cause by the parties. OSM selected a contractor to perform the required NEPA related services in support of the EIS in early December 2016. Currently, SJCC is working with all interested parties to maintain the three-year schedule to complete the requisite NEPA analysis. Though SJCC is free to continue operating under the existing permit during the three-year timeframe that the EIS is being conducted, any interruption of mining activities at SJCC could have an adverse impact on our results of operations and financial condition.
We may not have uncovered all risks associated with our 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.
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

48

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
•
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.



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 18 - 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 Annual 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 29, 2018, there were 1,385 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
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

 
 
 
 
2017
 
 
 
First Quarter
$
19.03

 
$
11.58

Second Quarter
15.28

 
4.33

Third Quarter
4.93

 
1.88

Fourth Quarter
3.13

 
0.95

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 Purchases of Equity Securities
The Company's purchases of its common stock during the year ended December 31, 2017 were as follows:
For the Year Ended
 
Total Number of Shares Purchased(1)
 
Average Price Paid per Share
December 31, 2017
 
92,212

 
$
12.18

__________________
(1) Shares purchased as indicated in this table represent the withholding of a portion of restricted shares to cover taxes on vested restricted shares and were not made pursuant to a publicly announced share repurchase plan or program.

Stock Performance Graph
The following performance graph compares the cumulative total stockholder return on our common stock for the five-year period December 31, 2012 through December 31, 2017 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

51

(iii) our Peer Group Index, which consists of Alliance Resource Partners LP, Cloud Peak Energy, and CONSOL Energy. The graph assumes that: 

•
You invested $100 in Westmoreland Coal Company common stock and in each index at the closing price on December 31, 2012;
•
All dividends were reinvested;
•
Annual re-weighting of the peer group indices; and
•
You continued to hold your investment through December 31, 2017.

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.
wlbstockperforminggraphfromb.jpg
 
As of December 31,
Company/Market/Peer Group
2012
 
2013
 
2014
 
2015
 
2016
 
2017
Westmoreland Coal Company
$
100.00

 
$
206.53

 
$
355.57

 
$
62.96

 
$
189.19

 
$
12.96

Nasdaq Financial Index
100.00

 
142.15

 
149.33

 
158.99

 
201.11

 
232.15

SPDR S&P Metals and Mining Index
100.00

 
94.62

 
70.70

 
34.98

 
72.07

 
87.33

Peer Group Index
100.00

 
117.23

 
107.11

 
34.16

 
68.50

 
63.32




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, 2017, 2016, and 2015 and our Consolidated Balance Sheets data as of December 31, 2017 and 2016 from our audited financial statements included in Item 8 - Financial Statements and Supplementary Data of this Annual Report on Form 10-K. Please refer to Note 20 - Quarterly Financial Data (Unaudited) to the consolidated financial statements contained in Item 8 - Financial Statements and Supplementary Data of this Annual Report on Form 10-K. Our historical results are not necessarily indicative of future results.
 
Years Ended December 31,
 
2017
 
2016(5)
 
2015
 
2014(5)
 
2013
 
(In thousands, except per share amounts)
Consolidated Statements of Operations Information
 
 
 
 
 
 
 
 
 
Revenues
$
1,384,568

 
$
1,477,960

 
$
1,419,518

 
$
1,131,000

 
$
686,055

Operating income (loss)(1)
39,212

 
38,130

 
(145,696
)
 
(48,664
)
 
20,319

Net loss applicable to common shareholders(2)
(71,340
)
 
(27,101
)
 
(213,645
)
 
(176,684
)
 
(9,204
)
Per common share (basic and diluted):
 
 
 
 
 
 
 
 
 
Net loss applicable to Westmoreland Coal Company
$
(3.91
)
 
$
(1.56
)
 
$
(12.24
)
 
$
(11.09
)
 
$
(0.78
)
Net loss applicable to common shareholders
(3.82
)
 
(1.47
)
 
(11.93
)
 
(11.08
)
 
(0.64
)
Consolidated Balance Sheets Information (end of period)
 
 
 
 
 
 
 
 
 
Net property, plant and equipment
$
741,835

 
$
835,521

 
$
746,842

 
$
986,603

 
$
538,946

Total assets(3)
1,389,099

 
1,584,909

 
1,415,979

 
1,740,389

 
881,427

Total debt(3)
1,048,407

 
1,109,066

 
1,020,179

 
959,312

 
322,459

Total deficit
(743,448
)
 
(690,117
)
 
(662,901
)
 
(400,876
)
 
(236,119
)
Other Consolidated Data
 
 
 
 
 
 
 
 
 
Net cash provided by (used in):
 
 
 
 
 
 
 
 
 
Operating activities
$
114,163

 
$
151,934

 
$
45,562

 
$
50,353

 
$
80,717

Investing activities
10,661

 
(155,694
)
 
(70,801
)
 
(432,772
)
 
(21,897
)
Financing activities
(82,802
)
 
40,122

 
36,723

 
338,706

 
(29,320
)
Capital expenditures
35,016

 
46,132

 
77,921

 
50,326

 
28,591

Adjusted EBITDA(4)
269,332

 
271,855

 
222,832

 
187,669

 
127,634

Tons sold
49,734

 
54,685

 
53,334

 
44,849

 
24,927

____________________
(1)
Includes:
a.
Asset impairment charge of $5.9 million in 2017 relating to WMLP's Kentucky operations, as well as $136.2 million in 2015, comprised of $133.1 million at ROVA and $3.1 million at Coal Valley.
b.
Derivative (gain)/loss of $(1.9) million, $(24.1) million, $5.6 million and $31.1 million in 2017, 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. Restructuring charges in 2014 were incurred in connection with our acquisition of our Coal - Canada operating segment, as well as our acquisition of the general partner of WMLP.
(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 and $0.1 million in 2015, 2014 and 2013, 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.
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

53

comparability of the information presented, and in conjunction with our consolidated financial statements included in this report.

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 advisory fees, restructuring, impairment, debt extinguishment, foreign exchange, derivative losses and/or gains, as well as other items which are not considered part of earnings from operations for comparison purposes to other companies’ normalized income. EBITDA and Adjusted EBITDA are supplemental measures of financial performance that are not required by, or presented in accordance with, GAAP. EBITDA and Adjusted EBITDA are key metrics used by us to assess our operating performance and as a basis for strategic planning and forecasting and we believe that EBITDA and Adjusted EBITDA are useful to an investor in evaluating our operating performance because these measures:

•
are used widely by investors to measure a company’s operating performance without regard to items excluded from the calculation of such terms, which can vary substantially from company to company depending upon accounting methods and book value of assets, capital structure and the method by which assets were acquired, among other factors;
•
are used by rating agencies, lenders and other parties to evaluate our creditworthiness; and
•
help investors to more meaningfully evaluate and compare the results of our operations from period to period by removing the effect of our capital structure and asset base from our operating results.

Neither EBITDA nor Adjusted EBITDA is a measure calculated in accordance with GAAP. The items excluded from EBITDA and Adjusted EBITDA are significant in assessing our operating results. EBITDA and Adjusted EBITDA have limitations as analytical tools, and should not be considered in isolation from, or as a substitute for, analysis of our results as reported under GAAP. For example, EBITDA and Adjusted EBITDA:

•
do not reflect our cash expenditures or future requirements for capital and major maintenance expenditures or contractual commitments;
•
do not reflect income tax expenses or the cash requirements necessary to pay income taxes;
•
do not reflect changes in, or cash requirements for, our working capital needs; and
•
do not reflect the significant interest expense, or the cash requirements necessary to service interest or principal payments, on certain of our debt obligations.
In addition, although depreciation and amortization are non-cash charges, the assets being depreciated and amortized will often have to be replaced in the future, and EBITDA and Adjusted EBITDA do not reflect any cash requirements for such replacements. Other companies in our industry and in other industries may calculate EBITDA and Adjusted EBITDA differently from the way that we do, limiting their usefulness as comparative measures. Because of these limitations, EBITDA and Adjusted EBITDA should not be considered as measures of discretionary cash available to us to invest in the growth of our business. We compensate for these limitations by relying primarily on our GAAP results and using EBITDA and Adjusted EBITDA only as supplemental data. The tables below show how we calculated Adjusted EBITDA, including a breakdown by segment, and reconcile Adjusted EBITDA to net loss, the most directly comparable GAAP financial measure.


54

Reconciliation of Adjusted EBITDA to Net Loss
Years Ended December 31,
 
2017
 
2016
 
2015
 
2014
 
2013
 
(In thousands)
Net loss
$
(73,135
)
 
$
(28,872
)
 
$
(219,095
)
 
$
(176,746
)
 
$
(11,274
)
Income tax expense (benefit)
(5,890
)
 
(48,059
)
 
(19,890
)
 
23

 
(6,678
)
Interest income
(4,101
)
 
(7,435
)
 
(7,993
)
 
(6,400
)
 
(1,366
)
Interest expense
118,657

 
121,819

 
101,311

 
82,320

 
39,937

Depreciation, depletion and amortization
121,054

 
185,267

 
140,328

 
109,361

 
74,430

Accretion of asset retirement obligations
45,132

 
40,423

 
38,892

 
31,028

 
21,894

Amortization of intangible assets and liabilities(1)
(890
)
 
(810
)
 
(1,010
)
 
138

 
665

EBITDA
200,827

 
262,333

 
32,543

 
39,724

 
117,608

Advisory fees(2)
5,423

 
—

 
—

 
—

 
—

Restructuring charges
—

 
—

 
656

 
14,989

 
5,078

Loss (gain) on foreign exchange
3,108

 
715

 
(3,674
)
 
4,016

 
—

Loss on impairment
5,872

 
—

 
136,210

 
—

 
—

Loss on extinguishment of debt
—

 
—

 
5,385

 
49,154

 
64

Acquisition-related costs(3)
—

 
568

 
5,959

 
26,785

 
—

Customer payments received under loan and lease receivables(4)
50,489

 
13,064

 
27,128

 
12,388

 
—

Derivative (gain) loss
(1,929
)
 
(24,055
)
 
5,587

 
31,100

 
—

Loss (gain) on sale/disposal of assets and other adjustments
2,342

 
11,646

 
5,290

 
3,431

 
(438
)
Share-based compensation
3,200

 
7,584

 
7,748

 
6,082

 
5,322

Adjusted EBITDA
$
269,332

 
$
271,855

 
$
222,832

 
$
187,669

 
$
127,634

__________________
(1)
Represents amortization of intangible assets and liabilities not included in Depreciation, depletion and amortization.
(2)
Amount represents fees paid to financial and legal advisers included in Selling and administrative in the Consolidated Statements of Operations related to the assessment of Westmoreland’s capital structure. These advisers, together with Westmoreland's management and board of directors, are developing and evaluating options to optimize Westmoreland’s overall capital structure.
(3)
Includes acquisition and transition costs included in Selling and administrative in 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.
(4)
Represents a return of and on capital. These amounts are not included in operating income (loss), 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.
 



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.
Overview

Westmoreland Coal Company produces and sells thermal coal primarily to investment grade utility customers under long-term, margin-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. Our coal operations include surface coal mines in the United States and Canada, underground coal mines in Ohio and New Mexico, a char production facility, and a 50% interest in an activated carbon plant. We also own the general partner of, and a majority of the equity interests in, WMLP, a publicly traded coal master limited partnership.
We sell almost all of our coal 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. 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.
We are a holding company and conduct our operations through subsidiaries. We have significant cash requirements to fund our ongoing debt obligations, pension contributions, heritage health benefit costs, and corporate overhead costs. The principal sources of cash flow to us are distributions from our operating subsidiaries.
Our operations are classified into six reporting segments: Coal - U.S., Coal - Canada, Coal - WMLP, Power, Heritage and Corporate. See Item 1 - Business - Overview and Item 1 - Business - Segment Information for a general description of our business and our business segments.

Recent Trends and Activities
One of the major factors affecting the volume of coal that we sell in any given period is the demand for coal-generated electric power. Numerous factors affect the demand for electric power and the specific demands of customers, including weather patterns, the presence of hydro- or wind-generated energy 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. More specifically, our financial results for the periods presented were impacted by several trends and activities, which are described below.
•
Weather. Weather patterns can have a significant impact on power demand and our ability to mine and produce coal. During the first half of 2017, we experienced unfavorable weather patterns in the markets in which we operate. In particular, the first half of 2017 was generally marked by mild weather, which depressed demand. In addition, our Kemmerer mine experienced unusually high amounts of precipitation in the first quarter of 2017, which increased our mining costs and temporarily restricted our ability to supply coal. These factors lowered our coal tons sold and our revenues in 2017. Weather conditions are inherently unpredictable and could have positive or negative impacts on operating conditions and demand in future periods.
•
Coal pricing. Our operations in Ohio and at Coal Valley are exposed to changes in the price of coal sold on the open market. The price of coal has been and continues to be volatile. Pricing in the last few years has generally been adversely influenced by reduced demand, political pressures and the price of competing fuel or energy sources, including natural gas. Recent pricing pressure has resulted in depressed revenues, net income and Adjusted EBITDA in recent years for those facilities affected by open market pricing. Whether pricing and volume softness persist in future periods is dependent upon fluctuations in market demand in those regions.

56

•
Cost reduction initiatives. While we always seek to run our business operations as lean and efficiently as possible, since 2016, we have undertaken specific initiatives aimed at centralizing and streamlining certain administrative functions and reducing costs throughout our organization. Cost reduction activities during 2016 resulted in disciplined capital expenditure decisions, lower inventory costs and reduced headcount, among other things. While the impacts of the cost reductions were organization-wide, the WMLP segment particularly benefited in 2016 and 2017 from lower fuel and labor costs at our Ohio mines as well as the impact of cost savings initiatives at Kemmerer. These factors, in turn, generally lowered operating costs in 2017 compared with 2016 and 2015, although we did incur some additional costs, including severance-related costs and additional costs resulting from redundancies created during these changes. Cost reduction activities are ongoing.
•
Early repayment of loan and lease receivables. Historically, our results, and particularly our free cash flow and Adjusted EBITDA, have been influenced by the amount of money collected related to loan and lease receivables owed to us from our customer at the Genesee mine. These loan and lease receivables represented the financed portion of amounts owed to Westmoreland for capital expenditures we had made on behalf of our customer. During the first quarter of 2017, we received $52.5 million from our customer at the Genesee mine, representing an accelerated full repayment of all outstanding loan and lease receivables. While we will continue to manage the Genesee mine and earn a management fee pursuant to the contract mining arrangement, which we anticipate continuing through 2030, we have no further obligation to make capital expenditures at the mine. Likewise, we do not anticipate collecting anything additional related to loan and lease receivables as the $52.5 million early repayment satisfied these obligations in full.
•
Acquisition and divestitures. On January 31, 2016, we acquired the San Juan mine for a total cash purchase price of $121.0 million, as described more fully in Item 1 - Business - Overview. This acquisition increased our revenues, tons sold, costs, and operating margins in periods subsequent to the purchase. Interest expense also increased in periods subsequent to the purchase as a result of the related financing.
Also, during the fourth quarter of 2017, we sold the power assets associated with the Roanoke Valley Power Facility ("ROVA") for $5.0 million in cash and exited the related power purchase and supply agreements, thereby freeing up an additional $6.2 million in net cash collateral. In addition, as a result of exiting the power purchase and supply agreements, we recognized $14.4 million of previously deferred revenue related to these contracts. We retained approximately $2.9 million of reclamation liabilities.
•
Significant contract renewals, changes and expirations. In June and December 2016, coal supply agreements at our Beulah and Jewett mines, respectively, terminated, resulting in lower coal tons sold in the subsequent periods. In addition, during 2017, we amended certain contracts with customers. One of our amended contracts, with a customer at our Kemmerer mine, provides for the sale of one million additional tons through 2018. While this amendment will result in more cash and more revenues from Kemmerer through 2018, it also lowered the amount of revenue recognized under the contract in 2017 as revenue recognition was deferred into 2018, when the lower priced coal tons will be sold.
Also, during 2017, our customer at the San Juan mine announced their intent to transition away from coal-generated power in 2022. While their plan still requires official approval, we have adjusted, on a prospective basis, the estimated useful lives of certain property, plant, and equipment at the mine as well as the mine's mineral reserve depletion rates to reflect the shorter useful lives of these assets. This change in estimate resulted in additional depreciation, depletion, and amortization expense during 2017 compared to 2016, and will continue to result in increased depreciation, depletion, and amortization expense in future periods.
•
Coal Valley mine. During mid-year 2017, we mined in a more challenging area at the Coal Valley mine. This was in part because we were operating Coal Valley in anticipation of either a sale or shutdown of the mine during 2017, which drove us to minimize the number of mining pits and delay maintenance on our equipment. In mid-2017, in part as a result of the delays in the negotiations for the sale of the mine, we made additional investments to extend the mine's life, which increased costs for equipment maintenance and development of the pit. This resulted in lower yields, lower revenues, and increased costs at the mine during 2017.
•
Equipment outage. During 2017, we experienced an unexpected dragline repair at one of our large mines in Canada, which lowered our production and increased our costs early in 2017.
•
Impairment charge. For the year ended December 31, 2017, we recorded an impairment charge of $5.9 million related to land and mineral rights in Kentucky within our Coal - WMLP segment which were determined to have no further economic value. During the fourth quarter of 2015, we incurred $136.2 million in impairment charges related to the ROVA asset group ($133.1 million) and certain immovable fixed assets at our Coal Valley mine ($3.1 million).

57

This decreased depreciation, depletion, and amortization expense for the Power and Coal - Canada segments in periods subsequent to the impairment.
•
Capital structure review. During 2017, management and our Board of Directors, with the assistance of outside advisors, began evaluating options to address upcoming debt maturities, as further described in "Liquidity and Capital Resources." Costs associated with this process were $5.4 million during 2017 and will increase in 2018.

Results of Operations
Year Ended December 31, 2017 Compared to Year Ended December 31, 2016
Consolidated Results of Operations
The following table shows the comparative consolidated results and changes between periods:
 
Years Ended December 31,
 
 
 
 
 
Increase / (Decrease)
 
2017
 
2016
 
$
 
%
 
(In millions)
Revenues
$
1,384.6

 
$
1,478.0

 
$
(93.4
)
 
(6.3
)%
Operating income
39.2

 
38.1

 
1.1

 
2.9
 %
Net loss applicable to common shareholders
(71.3
)
 
(27.1
)
 
(44.2
)
 
(163.1
)%
Adjusted EBITDA(1)
269.3

 
271.9

 
(2.6
)
 
(1.0
)%
Tons sold
49.7

 
54.7

 
(5.0
)
 
(9.1
)%
____________________
(1) 
Adjusted EBITDA , a non-GAAP measure, is defined and reconciled to net loss in Item 6 - Selected Financial Data.

Consolidated revenues decreased 6.3% and coal tons sold decreased 9.1% in 2017 compared with 2016. The decline in coal tons sold was driven in part by the Jewett and Beulah contract terminations in 2016 and ongoing demand softness in Ohio. Revenue was also driven lower by customer contract amendments, as further described in "Recent Trends and Activities." Offsetting these declines was revenue from reclamation at Jewett, higher prices at Coal Valley and strong performance from San Juan.

Operating income for 2017 increased $1.1 million compared with 2016. Offsetting the revenue declines were lower costs resulting from fewer tons sold, higher margin reclamation work at Jewett, and the non-recurrence of $66.8 million in charges and accelerated depreciation and depletion associated with the termination of production at the Jewett mine.

Net loss applicable to common shareholders increased $44.2 million primarily as a result of the factors discussed above, as well as the non-recurrence of a 2016 income tax benefit arising from the release of a valuation allowance on our net operating loss deferred tax asset as a result of the San Juan acquisition.

Consolidated Adjusted EBITDA in 2017 declined $2.6 million compared with the prior year. This decrease was driven by the aforementioned revenue declines as well as higher operating costs at certain of our Canadian mines. Offsetting these decreases, Adjusted EBITDA benefited from the 2017 $52.5 million early repayment of loan and lease receivables, representing an increase of $37.4 million over the prior year, as further described in "Recent Trends and Activities."

58

Coal - U.S. Segment Operating Results
The following table shows the comparative results and changes between periods for the Coal - U.S. segment:
 
Years Ended December 31,
 
 
 
 
 
Increase / (Decrease)
 
2017
 
2016
 
$
 
%
 
(In millions)
Revenues
$
573.7

 
$
651.7

 
$
(78.0
)
 
(12.0
)%
Operating income (loss)
40.1

 
(8.1
)
 
48.2

 
*

Adjusted EBITDA(1)
129.3

 
126.6

 
2.7

 
2.1
 %
Tons sold
20.0

 
24.1

 
(4.1
)
 
(17.0
)%
____________________
(1) 
Adjusted EBITDA, a non-GAAP measure, is defined and reconciled to net loss in Item 6 - Selected Financial Data.
* Not meaningful.

Revenues for the Coal - U.S. segment declined by 12.0% on 17.0% fewer coal tons sold in 2017 as compared with 2016. This decline was driven by the expiration of coal supply agreements at the Jewett and Beulah mines and amended contract terms with one of our merchant customers, which resulted in lower pricing, each as further described in "Recent Trends and Activities." These declines were partially offset by higher revenue from San Juan resulting from strong performance at the mine and 12 months of ownership in 2017 compared with 11 months in 2016. Revenue from reclamation at Jewett, which commenced in 2017, also offset the aforementioned revenue declines.

The segment generated $40.1 million in operating income in 2017 compared to an operating loss of $8.1 million in 2016. Contributing to this increase was higher operating income at our Jewett mine resulting from the high margin nature of the reclamation work performed subsequent to the December 31, 2016 termination of the coal supply agreement. In addition, 2016 operating income for the Jewett mine reflected $66.8 million in charges and accelerated depreciation and depletion associated with the termination of production. These charges did not recur in 2017, and contributed to the year-over-year increase in operating income. Offsetting this year-over-year increase was lower tons sold, as described previously, and higher depreciation, depletion and amortization expense from San Juan due to the longer term of ownership in 2017 and the decrease in estimated useful lives of certain San Juan assets and mineral rights further described in “Recent Trends and Activities.”

Adjusted EBITDA increased $2.7 million, or 2.1%, in 2017 compared with 2016 driven by high margin reclamation work at Jewett and increased EBITDA at San Juan, offset by lower coal tons sold from Beulah and Jewett. The aforementioned year-over-year changes in depreciation, depletion and amortization did not impact adjusted EBITDA as it is excluded from the calculation.
Coal - Canada Segment Operating Results
The following table shows the comparative results and changes between periods for the Coal - Canada segment:
 
Years Ended December 31,
 
 
 
 
 
Increase / (Decrease)
 
2017
 
2016
 
$
 
%
 
(In millions)
Revenues
$
438.3

 
$
415.6

 
$
22.7

 
5.5
 %
Operating income
8.9

 
39.1

 
(30.2
)
 
(77.2
)%
Adjusted EBITDA(1)
90.0

 
88.4

 
1.6

 
1.8
 %
Tons sold
22.8

 
22.8

 
—

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

Revenues for the Coal - Canada segment increased $22.7 million in 2017 compared with 2016, while tons sold remained flat year over year. The increase in revenue was driven by improved pricing on fewer tons at our Coal Valley mine. Lower tons sold at Coal Valley in 2017 was offset by increases in volume across several of our Canadian mines.


59

The segment generated operating income of $8.9 million, a decline of $30.2 million compared to the prior year. This decline was driven by increased costs across several Canadian mines, including costs associated with equipment outages and operational challenges described above at Coal Valley, each as further described in "Recent Trends and Activities."

Adjusted EBITDA increased $1.6 million to $90.0 million in 2017 compared to 2016, driven by lower operating income, offset by the early repayment of loan and lease receivables as discussed in “Recent Trends and Activities.”
Coal - WMLP Segment Operating Results
The following table shows the comparative results and changes between periods for the Coal - WMLP segment:
 
Years Ended December 31,
 
 
 
 
 
Increase / (Decrease)
 
2017
 
2016
 
$
 
%
 
(In millions)
Revenues
$
315.6

 
$
349.3

 
$
(33.7
)
 
(9.6
)%
Operating income
9.8

 
8.9

 
0.9

 
10.1
 %
Adjusted EBITDA(1)
68.7

 
79.3

 
(10.6
)
 
(13.4
)%
Tons sold
7.4

 
7.8

 
(0.4
)
 
(5.1
)%
____________________
(1) 
Adjusted EBITDA, a non-GAAP measure, is defined and reconciled to net loss in Item 6 - Selected Financial Data.

Compared with 2016, 2017 revenues for the Coal - WMLP segment decreased 9.6% on a 5.1% decline in tons sold.  This decline was driven by ongoing pressure on volumes and pricing in our Ohio market offset by increased sales volume at the Kemmerer mine.

Operating income increased 10.1%, or $0.9 million, in 2017 compared with 2016. Declines in revenue were offset by a corresponding decline in cost of sales due to fewer tons sold. Operating costs were also lower due to the impacts of cost savings initiatives, which, year-over-year, drove lower asset impairments, fewer losses on asset sales, and lower depreciation, depletion and amortization expense resulting from a smaller and aging fleet at our Ohio operations. These savings were partially offset by an increase in administrative costs, primarily associated with the ongoing capital structure review, and the $5.9 million asset impairment, all as further described in “Recent Trends and Activities.”

Adjusted EBITDA decreased $10.6 million in 2017 compared with 2016 largely as a result of the decline in revenue and tons sold. Note that Adjusted EBITDA excludes the positive operating income impact of lower depreciation, depletion and amortization expense and the impairment charges discussed above.
Power Segment Operating Results
The following table shows the comparative results and changes between periods for the Power segment:
 
Years Ended December 31,
 
 
 
 
 
Increase / (Decrease)
 
2017
 
2016
 
$
 
%
 
(In millions)
Revenues
$
77.2

 
$
86.6