~~to the CAIR,which requires 28 states in the Midwest and eastern seaboard of the United States to reduce power plant emissions thatcross state lines and contribute to ozone and/or fine particle pollution in other states. Under the CSAPR, the first phase~~of the nitrogen oxide and sulfur dioxide emissions reductions would commence in 2012 with further reduction effective in 2014. On December 15, 2011, the EPA finalized a supplemental rule making to require Iowa, Michigan, Missouri, Oklahoma and Wisconsin to make summertime reductions to nitrogen oxide emissions under the CSAPR ozone-season control program. However, on December 30, 2011, the U.S. Court of Appeals for the District of Columbia Circuit stayed the implementation of CSAPR pending resolution of judicial challenges to the rules and ordered the EPA to continue enforcing the CAIR until the pending legal challenges have been resolved. In August 2012, the U.S. Court of Appeals vacated the CSAPR in a 2-to-1 decision and left the CAIR standards in place. In January 2013, the court rejected the EPA’s request for en banc review. In March 2013, the Solicitor General’s office, on behalf of the EPA, and separately certain non-governmental organizations, filed petitions for writs of certiorari with the U.S. Supreme Court seeking review of the U.S. Court of Appeals decision, and the U.S. Supreme Court granted those petitions in June 2013. TheSupreme Court reversed the D.C. Circuit and upheld the rule, but remanded the case to the D.C. Circuit for further proceedings, which are ongoing. EPA issued an interim final rule in December 2014 that would require the first phase of reductions in 2015 and 2016, with the second phase of reductions beginning in 2017.

Other Programs. A number of other air-related programs may affect the demand for coal and, in some instances, coal mining directly. For example, the EPA has initiated a regional haze program designed to protect and improve visibility at and around national parks, national wilderness areas and international parks. The EPA’s new source review program under certain circumstances requires existing coal-fired power plants, when modifications to those plants significantly change emissions, to install the more stringentdirectly by regulating air emissions ~~control equipment required of new plants, and concerns about potential failures~~emitted by coal-fired EGUs. These include, but are not limited to, ~~comply have resulted in a number of high-profile enforcement actions and settlements over~~ the ~~years resulting in some instances in settlements under which operators install expensive new emissions control equipment. The~~ Acid Rain ~~program under Title IV of~~Program, interstate transport rules such as the ~~CAA continues~~Cross-State Air Pollution Rule, the Regional Haze Program, and requirements related to impose limits on overall sulphur dioxide and nitrogen oxide emissions from regulated EGUs. In June 2013, President Obama issued a Climate Action Plan, which included a focus on methane reductions from coal mines. In January 2015, the Administration issued its methane strategy, but it did not include requirements for coal mines. Indeed, in 2014 the D.C. Circuit upheld EPA’s decision not to list coal mines as a category of air pollution sources that endanger public health or welfare under Section 111 of the CAA and establish standards to reduce emissions from coal mines.New Source Review.

Effect on Westmoreland Coal Company. Our mines do not produce “compliance coal” for purposes of the Clean Air Act. Compliance coal is coal containing 1.2 pounds or less of sulfur dioxide per million British thermal ~~unit, or Btu.~~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. We are at particular risk of changes in applicable environmental laws with respect to the Jewett Mine, whose customer, the NRG Texas Power- Limestone Station, blends our lignite with compliance coal from Wyoming. Tightened nitrogen oxide and new mercury emission standards could result in an increased blend of the Wyoming coal to reduce emissions. Further, increased market prices for sulfur dioxide emissions and increased coal ash costs could also favor an increased blend of the lower ash Wyoming compliance coal. In such a case, NRG Texas Power has the option to increase its purchases of other coal, reduce purchases of our coal, or to terminate our contract. If NRG terminates the contact, sales of lignite would end and the Jewett Mine would commence final reclamation activities. NRG would pay for all reclamation work plus a margin.

Clean Water Act. The Clean Water Act ~~("CWA"~~(“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~~“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. ~~On April 21, 2014,~~In May 2015, the EPA and the ~~U.S. Army~~ Corps jointly issued a final rule defining “waters of ~~Engineers jointly released a proposed rule~~the United States” (“WOTUS Rule”) to clarify which waters and wetlands are subject to regulation under the CWA. ~~Recent~~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 ~~decisions,~~challenges and regulatory actions ~~and proposed legislation have created~~create ongoing uncertainty over CWA jurisdiction and permitting requirements, ~~that~~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.

Endangered Species Act. The Federal Endangered Species Act ~~("ESA"~~(“ESA”), and similar state laws, protect any species listed as threatened with ~~extinction.~~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. Based on the species that~~

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~~have been identified~~ESA and ~~the current application of applicable~~equivalent state laws and ~~regulations,~~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 ~~that there are~~ any of these species ~~protected~~protections under the ESA or similar state laws ~~that would~~will have a materially ~~and adversely affect~~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"~~(“RCRA”), and comparable state statutes, although certain mining and mineral beneficiation wastes and certain wastes derived from the combustion of coal currently are exempt from regulation as hazardous wastes under RCRA. The EPA has limited the disposal options for certain wastes that are designated as hazardous wastes under RCRA. Furthermore, it is possible that certain wastes generated by our operations that currently are exempt from regulation as hazardous wastes may in the future be designated as hazardous wastes, and therefore be subject to more rigorous and costly management, disposal and clean-up requirements.

The EPA determined that coal combustion residuals (“CCR”) do not warrant regulation as hazardous wastes under RCRA in May 2000. Most state hazardous waste laws do not regulate CCR as hazardous wastes. The EPA also concluded that beneficial uses of CCR, other than for mine filling, pose no significant risk and no additional national regulations of such beneficial uses are needed. However, the EPA determined that national non-hazardous waste regulations under RCRA are warranted for certain wastes generated from coal combustion, such as coal ash, when the wastes are disposed of in surface impoundments or landfills or used as minefill. EPA Administrator Gina McCarthy signed the final rule relating to the disposal of CCR from electric utilities on December 19, 2014, ~~and submitted it to~~which was published in the Federal Register ~~for publication.~~on April 17, 2015 ("CCR Rule"). The ~~final rule~~CCR Rule regulates CCR as solid waste under ~~RCRA. The final rule~~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~~Internet posting requirements. The ~~rule~~CCR Rule is largely silent on the reuse of coal ~~ash,~~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 ~~the EPA has plans~~are not required to, develop ~~in 2015~~and submit CCR permit programs to EPA for approval. On March 1, 2018, EPA Administrator Scott Pruitt issued a ~~conceptual model for beneficial uses~~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. These~~ash permit programs.

Continued changes in the management of CCR could increase both our and our customers’ operating costs and potentially ~~reduce~~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 ~~also known as CERCLA~~("CERCLA" or ~~Superfund,~~"Superfund") and similar state laws, ~~responsibility for~~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 ~~course~~disposal, release, or spilling of ~~our~~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 ~~have generated~~be subject to liability under CERCLA and ~~may generate wastes that fall within CERCLA’s definition of hazardous substances.~~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. ~~We also must comply with reporting requirements under the Emergency Planning and Community Right-to-Know Act and the Toxic Substances Control Act.~~

Climate Change Legislation and Regulations. Numerous proposals for federal and state legislation have been made relating to GHG emissions (including carbon dioxide) and such legislation could result in the creation of substantial additional

costs in the form of taxes or required acquisition or trading of emission allowances. Many of the federal and state climate change legislative proposals use a “cap and trade” policy structure, in which GHG emissions from a broad cross-section of the economy would be subject to an overall cap. Under the proposals, the cap would become more stringent with the passage of time. The proposals establish mechanisms for GHG sources such as power plants to obtain “allowances” or permits to emit GHGs during the course of a year. The sources may use the allowances to cover their own emissions or sell them to other sources that do not hold enough emissions for their own operations. Some states, including California, and regional groups including a number of states in the northeastern and mid-Atlantic regions of the USUnited 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, has issued a notice of finding and determination that emissions of carbon dioxide, methane and other GHGs present an endangerment to human health and the environment, which allows the EPA to begin regulating emissions of GHGsacting under existing provisions of the ~~federal~~ Clean Air ~~Act. The EPA~~Act, has begun ~~to implement~~regulating emissions of GHG, including the enactment of GHG-related reporting and permitting rules as described above. ~~In June~~However, as discussed above, most of ~~2014,~~these regulations are currently subject to judicial review pending the ~~U.S. Supreme Court overturned EPA’s GHG permitting rules~~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 ~~they required permits based solely on emissions of GHG. Large sources of air pollutants could still be required~~ to ~~install GHG emission reduction technology. Underground coal mines remain subject to EPA’s GHG Reporting~~

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~~Program,~~ which ~~required mines to submit annual GHG emission estimates to EPA, but that program has not been extended to surface coal mines.~~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, ~~on us~~ will depend on a number of factors, including whether GHG sources in multiple sectors of the economy are regulated, the overall GHG emissions cap level, the degree to which GHG offsets are allowed, the allocation of emission allowances to specific sources and the indirect impact of carbon regulation on coal prices. We may not recover from our customers the costs related to compliance with regulatory requirements imposed on us due to limitations in our agreements.

Passage of additional state or federal laws or regulations 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 ~~treaties,~~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 ~~coal and power plant~~ revenues.

~~Bonding Requirements~~. Federal and state laws require mine operators to assure, usually through the use of surety bonds, payment of certain long-term obligations, including the costs of mine closure and the costs of reclaiming the mined land. The costs of these bonds have fluctuated in recent years, and the market terms of surety bonds have generally become more favorable to us. Surety providersWe are requiring smaller percentages of collateral to secure a bond, which will require us to provide less cash to collateralize bonds to allow us to continue mining. These changes in the terms of the bonds have been accompanied, at times, by an increase in the number of companies willing to issue surety bonds. As of December 31, 2014, we had posted an aggregate of $461.4 million in surety bonds for reclamation purposes, with approximately $102.2 million of cash collateral.

~~Regulation applicable to ROVA.~~ With respect to our Power segment, ROVA is among the newer and cleaner coal-fired power plants in the United States. Under Title IV of the Clean Air Act, ROVA is exempt from, but may opt-in to receive allocations of sulfur dioxide emission allowances. The plants are among the lowest coal-fired emitters of mercury in the country. All preliminary emission testing performed in 2014 has demonstrated that both ROVA units 1 and 3 will be compliant with the MATS Rule. Official testing for compliance with the MATS Rule will be performed in segments, beginning in January 2015. The final emissions testing report for MATS Rule compliance is due to the EPA by October 13, 2015. Currently, ROVA is a consumer of sulfur dioxide allowances and nitrogen oxide credits, and we expect an increase in costs associated with nitrogen oxide allowances at ROVA. With regard to coal ash regulations, ROVA landfills its combustion waste. The landfills are lined and we believe they meet North Carolina Department of Solid Waste regulations. However, on December 19, 2014, the EPA Administrator executed a final rule relating to the disposal of CCR for electric utilities. The rule regulates CCR as a solid waste under RCRA and establishes national minimum criteria for existing and new CCR landfills, surface impoundments and lateral expansions. The criteria include location restrictions, design and operating criteria, groundwater monitoring and corrective action, closure requirements and post-closure care and recordkeeping, notification and internet posting requirements. At this time we are unable to predict the impact that any new regulations might have on our operations.

~~An important factor relating to the impact of GHG-related legislation and regulations and any other environmental regulations on our Power segment will be our ability to recover the costs incurred~~required to comply with ~~any regulatory requirements that~~numerous other federal, state, and local environmental laws and regulations in addition to those previously discussed. Such additional laws include, for example, the ~~government ultimately imposes. We may not be able to recover~~Emergency Planning and Community Right-to-Know Act, the costs related to compliance with regulatory requirements imposed on us due to limitations in our power purchase agreements. If we are unable to recover such costs incurred by ROVA through allowances or other methods, it could have a material adverse effect on our results of operations at ROVA.Toxic Substance Control Act, the Migratory Bird Treaty Act, and the Safe Drinking Water Act.

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~~Canadian~~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 ~~following is intended as~~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 ~~general overview~~dramatic increase in the dollar penalties assessed by MSHA for citations issued over the past several years. Most of ~~certain~~the states in which we operate have inspection programs for mine safety and health. Collectively, federal, state and provincial ~~laws~~safety and health regulations in ~~Alberta~~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:



	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 ~~federal laws applicable therein~~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 ~~their potential effects upon~~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

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. ~~We note~~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:

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.

However, on March 28, 2017, EPA filed a motion, pursuant to President Trump’s March 28, 2017 EI Order, requesting that the ~~consequences~~consolidated cases be held in abeyance pending completion of EPA’s review of the rule and ~~penalties arising~~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 ~~application of any~~power sector by 32% from 2005 levels by 2030. The “Clean Power Plan,” promulgated pursuant to Section 111(d) of the ~~below listed enactments are varied and fact specific. Accordingly,~~CAA, would impose stringent standards on existing fossil fuel-fired EGUs that reflect the ~~summary that follows should not be considered a comprehensive or conclusive~~EPA’s assessment of the ~~possible outcomes~~“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 ~~contravention~~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 ~~legislation discussed below:~~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.

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).

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-

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).

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.

~~Responsible Energy Development~~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.

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.

Endangered Species Act. The ~~Responsible Energy Development~~Federal Endangered Species 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”~~(“ESA”), and ~~its underlying regulations, governs~~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 ~~management~~OSM and ~~disposition of rights in Crown owned mines~~state agencies to administer the ESA and minerals. The AER recently assumed jurisdiction over issuing exploration authorizations under the MM Act, which any person conducting mining exploration in Alberta is required to obtain in advance of carrying out an exploration program. Exploration programs under the MM Act areensures that species subject to ~~investigations~~its provisions are protected from mining-related impacts. Protection of endangered and ~~inspections and a contravention of an exploration authorization or of the provisions of the MM Act may result in cancellation of that exploration authorization and/or financial penalties.~~

~~Coal Conservation Act.~~ The Coal Conservation Act (the “CC Act”), and its underlying rules, applies to every mine, coal processing plant and in situ coal scheme in the Province of Alberta, and to all coal produced and transported in Alberta. The CC Act imposes permitting, licensing and approval requirements on operators of coal mines and coal processing plants. The CC Act imposes certain environmental conservation requirements on mine operators in relation to, among other things, pollution control, surface abandonment, and prevention of waste. Similar to the US bonding requirements mentioned above, the 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.

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~~The Crown Minerals Act.~~ Similar to the MM Act in Alberta, the Crown Minerals Act (the “CM Act”), and its underlying regulations, governs the management and disposition of rights in Crown owned mines and minerals. The Saskatchewan Ministry of Economy administers the CM Act and the issuance of dispositions authorizing the exploration and development of coal resources in the province. Contravention of the terms of a Crown disposition or the provisions of the CM Act may result in cancellation of that disposition and/or financial penalties, both of which may have a material adverse effect on our business.

~~The Ecological Reserves Act.~~ The Ecological Reserves Act (the “ER Act”) protects unique, natural ecosystems and landscape features in Saskatchewan through the designation of Crown land as ecological reserves. Under the ER Act, the Lieutenant Governor in Council may make regulations and orders designating any Crown land as an ecological reserve, enlarging any ecological reserve, and restricting the activities which may be carried out on an existing ecological reserve. Designation of either of our Saskatchewan mine properties as an ecological reserve may restrict our mining activities on those properties, or cause us to modify mining plans; however, we do not have any reason to believe that either of our Saskatchewan properties are at risk of being designated an ecological reserve at this time.

~~The Environmental Assessment Act.~~ The Environmental Assessment Act (the “EA Act”) provides a means to ensure that development proceeds with adequate environmental safeguards and in a manner broadly understood by and acceptable to the public through the integrated assessment of environmental impact. Under the EA Act, the Saskatchewan Ministry of Environment is responsible for administering environmental assessments, and issuing approvals and other authorizations in respect of certain aspects of coal mining operations in Saskatchewan that have the potential to impact the environment. Similar to the AER’s powers in relation to environmental impact assessments issued under the EPEA, the Ministry of Environment may issue an EA Act approval on any terms and conditions considered necessary or advisable to protect the environment. The Ministry of Environment has broad enforcement powers under the EA Act, including enjoining a development contrary to the EA Act or the terms and conditions of any ministerial approval, conducting investigations, and issuing financial penalties for offenses under the EA Act; all of which may have a material adverse effect on our business, depending on the specific circumstances surrounding the enforcement action taken by the Ministry of Environment.

~~The Environmental Management and Protection Act, 2002.~~ The Environmental Management and Protection Act, 2002 (the “EMP Act”), and its underlying regulations, protects the air, land and water resources of Saskatchewan through regulating and controlling potentially harmful activities and substances. The Saskatchewan Ministry of Environment administers and enforces provisions under the EMP Act that concern unauthorized discharges of substances into the environment, contaminated sites, surface land reclamation, hazardous waste, water quality, and activities around water bodies. The Saskatchewan Ministry of Environment may exercise broad enforcement powers under the EMP Act, including conducting compliance checks, inspections and investigations, issuing environmental protection orders, suspending or canceling operating authorizations, demanding cost recovery or charging us for an offence under the EMP Act; all of which may have a material effect on our business, depending on the specific circumstances surrounding the enforcement action taken by the Ministry of Environment.

~~The Provincial Lands Act.~~ The Provincial Lands Act (the “PL Act”) creates authority for the Saskatchewan Ministry of Environment to carry out its responsibilities in relation to the management, transfer, sale, lease or other disposition of Crown lands, including lands used for coal mining. The Ministry of Environment also administers the enforcement and compliance provisions of the PL Act, which may include cancellation of a disposition where its terms and conditions or the provisions of the legislation have been contravened and to issue financial penalties in respect of offenses under the PL Act. Similar to contraventions of other legislation discussed in this section, an enforcement action or a penalty has the potential to constitute a material adverse effect on our operations.

~~The Wildlife Act, 1998.~~ The Wildlife Act, 1998 (the “Wildlife Act”) provides for the management, conservation and protection of wildlife resources through the issuance and revocation of licenses, the prosecution of wildlife offenses and the establishment of annual hunting seasons. The Wildlife Act includes provisions to designate and protectthreatened 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 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 ~~Wildlife Act;~~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 ~~that there are~~ any of these species ~~protected~~protections 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~~ESA or similar state laws will have a ~~material~~materially adverse 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

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verify compliance, investigations of violations, issuance of warning, directions by Fishery Inspectors, authorizations and Ministerial orders, and court actions, such as injunctions, prosecution, court orders upon conviction and civil suits for recovery of costs.

~~Canadian Environmental Assessment Act, 2012.~~ The Canadian Environmental Assessment Act, 2012 (the “CEAA”) is the primary federal statute for environmental assessments. The CEAA requires that an environmental assessment for projects that are listed in the Regulations Designating Physical Activities be completed prior to federal authorities making decisions that allow a project to proceed (i.e. prior to issuing certain licenses, disposing of federal lands, providing funding for a project). Projects that require an environmental assessment under the CEAA include, among others, the construction, operation, decommissioning and abandonment, in a wildlife area or a migratory bird sanctuary, of a new mine; the construction, operation, decommissioning and abandonment of a new dam or dyke or the expansion of an existing dam or dyke in certain circumstances; the construction, operation, decommissioning and abandonment of a new structure for the diversion of certain amounts of water; and the construction, operation, decommissioning and abandonment of a new coal mine with a coal production capacity of 3,000 t/day or more.

~~Canadian Environmental Protection Act, 1999.~~ The Canadian Environmental Protection Act, 1999 (the “CEPA”) focuses on the prevention and management of risks posed by toxic and other harmful substances, as well as management of environmental and human health impacts of hazardous wastes, environmental emergencies and other sources of pollution. Certain substances used and/or produced, as well as downstream wastes generated through the course of our mining and processing operations may bring our business under the purview of the CEPA. The CEPA provides the authority to carry out inspections and investigations to ensure that regulations made under the CEPA and the CEPA itself are followed. Similar to the enforcement provisions of other environmental laws and regulations discussed herein, enforcement tools under the CEPA may include warnings, directions to prevent releases, tickets, orders requiring remedial measures, injunctions, prosecution, and financial penalties. Subject to the specific circumstances of a contravention of the CEPA, an enforcement action taken under the CEPA has the potential to cause a material adverse effect to our business.

~~Species at Risk Act.~~ The purposes of the Species at Risk Act (the “SARA”) are to prevent wildlife species in Canada from disappearing, to provide for the recovery of wildlife species that no longer exist in the wild in Canada, endangered, or 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~~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 ~~1994.~~ ~~Environment Canada is responsible for implementing the Migratory Birds Convention Act, 1994 (the “MBC 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 ~~provides~~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 ~~protection~~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 ~~conservation~~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 ~~migratory bird populations~~facilities at which hazardous substances have been released by ~~regulating potentially harmful human activities. The MBC Act prohibits, among other things, the deposit of harmful substances in waters~~previous owners or ~~areas frequented by migratory birds and a permit must~~operators. We may be ~~issued~~responsible under CERCLA for all ~~activities affecting migratory birds. Any person that commits an offence under the MBC Act is liable to a fine~~ or ~~to imprisonment. A contravention~~part of the ~~MBC Act may result in cancellation or suspension~~costs of ~~a permit issued under the MBC Act~~cleaning up facilities at which such substances have been released and ~~a compensatory order~~ for ~~costs incurred by others~~natural resource damages. We have not, to our knowledge, been identified as a ~~result~~potentially responsible party under CERCLA, nor are we aware of ~~a contravention may be issued.~~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. ~~Similar~~Numerous proposals for federal and state legislation have been made relating to GHG emissions (including carbon dioxide) and such legislation could result in the creation of substantial additional

costs in the form of taxes or required acquisition or trading of emission allowances. Many of the federal and state climate change ~~legislation, regulations,~~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 ~~US,~~northeastern and mid-Atlantic regions of the ~~direct~~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 ~~various~~additional state or federal laws or regulations or international initiatives regarding GHG ~~regulations, existing~~emissions or other actions to limit carbon dioxide emissions could result in fuel switching from coal to other fuel sources by electricity generators and ~~proposed~~thereby reduce demand for our coal or indirectly the prices we receive in ~~Canada,~~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 ~~business. Equipment that meets future emission standards may not be available on an economic basis~~revenues.

We are required to comply with numerous other federal, state, and ~~other compliance methods~~local environmental laws and regulations in addition 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~~those previously discussed. Such additional laws include, 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~~example, the Emergency Planning and ~~result in fines, penalties~~Community Right-to-Know Act, the Toxic Substance Control Act, the Migratory Bird Treaty Act, 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.Safe Drinking Water Act.

Alberta’s Climate Change and Emissions Management Act (the “CCEM Act”) and its accompanying Specified Gas Emitters Regulation (the “SGE Regulation”) requires a reduction in GHG emissions intensity for certain large GHG emitting facilities in Alberta. This system features emissions trading between regulated facilities and allows the use of offsets generated by projects in Alberta. Generally, the SGE Regulation establishes that companies emitting more than 100,000 tons of direct emissions in 2003, 2004, 2005, and 2006 in commercial operation must reduce their net emissions intensity by 12%. New facilities must reduce their emissions by 2% per year, beginning on their 4^th ~~year of operation. There are financial penalties for~~

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~~non-compliance for every ton of carbon dioxide equivalent over a facility’s net emission intensity limit as well as for contraventions of other provisions contained in the SGE Regulation.~~

Future federal legislation, including the implementation of potential international requirements enacted under Canadian law, as well as provincial emissions reduction requirements, may require the reduction of GHG or other industrial air emissions, or emission intensity, from our operations and facilities. Mandatory emissions reduction requirements may result in increased operating costs and capital expenditures. We are unable to predict the impact of emissions reduction legislation on our business and it is possible that such legislation may have a material effect on our business, financial condition, results of operations and cash flows.

Power Segment

~~General~~

~~We own~~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 iswas held by our wholly-owned subsidiary Westmoreland Partners. All of the tangible and intangible assets of Westmoreland Partners ~~are~~were encumbered by liens securing our 8.75% Notes and Term Loan.

~~Coal Supply~~

~~ROVA purchases coal under short-term contracts from coal suppliers with identified reserves located in Central Appalachia.~~

~~Customer~~

ROVA supplies a portion of the power it produces to DNCP and generates revenues from such sales, as well as through the settlement of related power hedging arrangements. In 2014, the sale of power by ROVA to DNCP accounted for approximately 8% of our consolidated revenues. We are impacted by seasonality due to the impact of weather on customer demand and scheduled maintenance outages typically performed in the spring and fall.

Westmoreland Partners iswas party to a consolidated power purchase and operating agreement (the “Consolidated Agreement”) with Virginia Electric Power Company, ~~that is scheduled to terminate in March 2019. The Consolidated Agreement provides~~which provided for the sale to DNCP and its affiliates of all of ROVA’s net electrical output and dependable capacity. ~~The~~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 ~~permits~~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 during periods when it is uneconomical~~ROVA. Further, we were required to ~~operate~~post collateral to cover certain projected long-term losses under these hedging arrangements based on the ~~ROVA units. While~~market price for power.

As we ~~expect to continue~~were no longer required to operate ROVA during high demand periods, we expect the facility to remain idle during low demand periods, during which we may meet DNCP’s power needs by purchasing power from a third party provider at a fixed price under the ~~terms~~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 ~~hedging agreements. We refer~~ to the ~~power which we have purchased from~~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 ~~third party provider as~~result of an impairment charge of $133.1 million, with the fixed-price purchased power. The fixed-price purchased power contracts cover the period from April 2014 to March 2019 and contracted power prices range from $41.05 to $56.33 megawatts per hour, with a weighted average contract price of $43.71 over the remaining contract lives. Alternatively, we have the option to operate the ROVA units, sell our produced power to DNCP and resell the fixed-price purchased power into the open market.

If we choose to operate the ROVA facilities and resell our fixed price purchased power into the open market, any such resales are made at prevailing market rates. If the prevailing market price for power falls below the level of our hedged position during periods when we are reselling the fixed price purchased powercharge included in the ~~open market, those resales would result in losses to us. For~~Loss on impairment on the Consolidated Statements of Operations for the year ended December 31, ~~2014, we incurred net losses related to these hedging arrangem~~ents of $31.1 million. Based on current market pricing trends, we expect to experience losses from time to time under these hedging arrangements when the market price for power is not commensurate with our hedged position. See “Risk Factors - Risks Relating to our Business and Operations - Our hedging arrangement in connection with the ROVA Consolidated Agreement may result in losses if the market price for power drops below the level of our hedged position.”

We incurred restructuring charges related to ROVA of $5.1 million and $0.5 million for the years ended December 31, 2013 and December 31, 2014, respectively, primarily related to consulting and legal fees.

~~Material Effects of Regulation Applicable to ROVA~~

With respect to our power segment, ROVA is among the newer and cleaner coal-fired power plants in the United States. Under Title IV of the Clean Air Act, ROVA is exempt from, but may opt-in to receive allocations of sulfur dioxide emission allowances. The plants are among the lowest coal-fired emitters of mercury in the country. We are evaluating whether

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ROVA could be a net consumer or seller of mercury allowances under new and pending regulations. Currently, ROVA is a consumer of sulfur dioxide allowances and nitrogen oxide credits, and we expect an increase in costs associated with nitrogen oxide allowances at ROVA. With regard to coal ash regulations, ROVA landfills its combustion waste. Landfills are lined and meet strict North Carolina Department of Solid Waste regulations.

An important factor relating to the impact of GHG-related legislation and regulations on our power segment will be our ability to recover the costs incurred to comply with any regulatory requirements that the government ultimately imposes. We may not recover the costs related to compliance with regulatory requirements imposed on us due to limitations in our power purchase agreements. If we are unable to pass through such costs incurred by ROVA to Dominion Virginia Power or recoup them in another manner such as through allowances, it could have a material adverse effect on our results of operations at ROVA.

For additional discussion of the extensive regulation with respect to environmental and other matters by federal, state and local authorities affecting our power segment, see Item 1 under “Coal Segment - ~~Material Effects of Regulation.~~”2015.

Heritage Segment

Our Heritage ~~Segment~~segment includes the cost of heritage benefits we provide to former mining operation employees. The heritage costs consist of payments to our retired workers for medical benefits, workers’ compensation benefits, black lung benefits and combined benefit fund premiums to plans for United Mine Workers of America (“UMWA”) retirees required by statute. ~~Canadian heritage costs include retiree medical benefits, statutory workers’ compensation premiums, and contributions to pension plans.~~

Corporate Segment

Our Corporate ~~Segment~~segment includes primarily corporate administrative expenses and also includes business development expenses. In addition, the Corporate ~~Segment~~segment contains our captive insurance company, ~~Westmoreland Risk Management Inc. (“WRM”),~~WRMI, through which we have elected to retain some of our operating risks. ~~WRM~~WRMI provides our primary layer of property and casualty insurance in the ~~United States.~~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 ~~excellent~~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:



	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

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.

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.

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.

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.

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.

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.

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.

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.

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.

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.

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.

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 ~~(303) 992-6463~~(855) 922-6463 or by mail at Westmoreland Coal Company, 9540 South Maroon Circle, Suite ~~200,~~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 ~~Business~~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 ~~Operations~~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:

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;

difficulty retaining, attracting or replacing key employees;

employees to be distracted from performance of their duties or more easily attracted to other career opportunities; and

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.

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, ~~2014,~~2017, we had a total outstanding indebtedness of approximately $1,076 million as detailed in ~~$998.0 million~~Note 8 - Debt And Lines Of Credit~~, including (i) $350 million in principal amount of 8.75% Notes, (ii) $350 million in principal amount under~~ to the ~~Term Loan and (iii) $33.1 million of borrowings and supported letters of credit under our Revolving Credit Facility, respectively, leaving $16.9 million of undrawn availability thereunder.~~consolidated financial statements. Our substantial amount of indebtedness could have important ~~consequences for you.~~consequences. For example, it could:

increase our vulnerability to adverse economic, industry or competitive developments;

result in an event of default if we fail to satisfy our obligations with respect to the 8.75% Notes, the Term Loan, the ~~Revolving Credit Facility~~San Juan Loan, the Revolver or other debt or fail to comply with the financial and other restrictive covenants contained in the ~~Indenture,~~8.75% Notes, the Term Loan, ~~Credit Agreement,~~ the ~~Revolving Credit Facility Agreement~~San Juan Loan, the Revolver agreement or agreements governing our other indebtedness, which event of default could result in all of our debt becoming immediately due and payable and could permit our lenders to foreclose on our assets securing such debt or otherwise recover that debt from us;

require a substantial portion of cash flow from operations to be dedicated to the payment of principal, premium, if any, and interest on our indebtedness, therefore reducing our ability to use our cash flow to fund our operations, capital expenditures and future business opportunities;

make it more difficult for us to satisfy our obligations with respect to the 8.75% Notes, the Term Loan, the San Juan Loan and the ~~Revolving Credit Facility;~~Revolver;

increase our cost of borrowing;

restrict us from making strategic acquisitions or causing us to make non-strategic divestitures;

limit our ability to service our indebtedness, including the 8.75% Notes, the Term Loan, San Juan Loan and the ~~Revolving Credit Facility;~~Revolver;

limit our ability to obtain additional financing for working capital, capital expenditures, debt service requirements, acquisitions and general corporate or other purposes;

limit our flexibility in planning for, or reacting to, changes in our business or the industry in which we operate, placing us at a competitive disadvantage compared to our competitors who are less highly leveraged and who therefore may be able to take advantage of opportunities that our leverage prevents us from exploiting; and

prevent us from raising the funds necessary to repurchase all 8.75% Notes tendered to us upon the occurrence of certain changes of control, which failure to repurchase would constitute a default under the ~~Indenture.~~8.75% Notes.

The occurrence of any one of these events could have a material adverse effect on our business, financial condition, results of operations, prospects and our ability to satisfy our obligations under the 8.75% Notes, the Term Loan, the San Juan Loan and the ~~Revolving Credit Facility.~~

Revolver. In conjunction with our acquisition of the Westmoreland Resources GP, LLC, the general partner of WMLP, WMLP entered into the WMLP ~~Financing Agreement~~Term Loan to refinance ~~WMLP’s~~it’s indebtedness. The WMLP Financing Agreement provides for up to $295 million of first priority secured term loans, with $175 million currently funded and maturing in December 2018, and the remaining $120 million available in the form of delayed draw term loans, which may be used to fund certain permitted acquisitions by WMLP until December 2015. Additionally, there is an accordion feature that takes effect when the delayed draw term loan feature expires which makes a further $150 million available for use to fund acquisitions during the remaining three years until the maturity of the WMLP Loan. Although the WMLP Term Loan ~~will be~~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 ~~will be~~are obligors under the WMLP ~~Financing Agreement~~Term Loan and the ~~WMLP Loan~~loan will be non-recourse to Westmoreland and its wholly owned ~~subsidiaries.~~

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. On January 23, 2014, Moody’s Investors Service (“Moody’s”) concluded its review of our ratings which was initiated on December 26, 2013, following the announcement of our acquisition of the Canadian Subsidiaries, and confirmed our

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existing credit ratings. In November 2014, both Moody’s and Standard & Poor’s Ratings Service raised our credit rating. However, we cannot assure you that rating agencies will not downgrade the credit ratings of our long-term senior secured debt in the future. Any such downgrade, or any perceived decrease in our creditworthiness, could impede our ability to refinance our existing debt, secure new debt or otherwise increase our future cost of borrowing and could create additional concerns on the part of our customers, partners and investors about our financial condition and results of operations.

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.~~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, ~~and~~ 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 ~~indebtedness.~~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, or 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 ~~Revolving Credit Facility~~Revolver could declare all outstanding principal and interest to be due and payable, the lenders under the ~~Revolving Credit Facility~~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 ~~Revolving Credit Facility~~Revolver could foreclose on the assets securing our debt to them and we could be forced into

bankruptcy or liquidation. If we are not able to generate sufficient cash flow from operations, we may need to seek ~~an amendment~~amendments to ~~the Indenture, the Term Loan Credit Agreement or the Revolving Credit Facility Agreement~~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.

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 ~~2014,~~2017, our Coal - U.S. ~~- Segment~~segment derived approximately ~~62.7%~~83% of its total revenues from coal sales to ~~five power plants:~~four customers: Public Service Company of New Mexico (36%), Colstrip Units 3&4 ~~(17.6%), Naughton Power Station (14.0%), Limestone Generating Station (13.8%~~(24%), Colstrip Units 1 ~~& 2 (10.9%~~&2 (12%) and ~~Coyote Station (6.4%~~AEP (11%). ~~In 2014, our~~Our Coal - Canada ~~Segment~~segment derived approximately ~~54.8%~~86% of its total revenues from coal sales to ~~two~~three customers: SaskPower ~~(37.2%~~(44%), Trafigura Pte. Ltd. (26%) and ATCO ~~(17.6%~~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. ~~Ten~~Sixteen of our ~~twelve~~18 mines are dedicated to supplying customers located

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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.

~~Additionally, certain~~Certain of our long-term contracts are set to expire in the next several years. Our contracts ~~with~~to fuel the Sherburne County Station ~~are~~in Minnesota have historically been three-year rolling contracts, and as of December 31, 2017, we have contracted tons through 2018 with ~~one-third of the tonnage expiring on an annual basis.~~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, ~~expires~~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 ~~is not expected~~we have been notified that our contract with Colstrip Units 1 & 2 will be terminated three years early in 2019 which equates to ~~be renewed.~~approximately 2.3 million tons annually and $10.7 million in operating income annually. Our contract with Colstrip Units 3 & 4 expires in December 2019. Should we be unable to successfully renew any ~~or all~~ of ~~these~~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. The long term agreements we acquired or subsequently negotiated in connection with the Canadian Acquisition have long-remaining terms with the exception of the contract applicable to Poplar River Mine, which is set to expire in 2015. Coal supply agreements also typically contain force majeure provisions allowing temporary suspension of performance by us or the customer during the duration of specified events beyond the control of the affected party. Such agreements may also prohibit us from passing certain increased costs resulting from changes in regulations to our customers. Additionally, many of our coal supply agreements contain provisions allowing customers to suspend acceptance of coal shipments if coal delivered does not meet certain quality thresholds.

Similarly, interruption in the purchase of power by DNCP could also negatively affect our revenues. During the year ended December 31, 2014, the sale of power by ROVA to DNCP accounted for approximately 8% of our consolidated revenues. Although ROVA supplies power to DNCP under long-term power purchase agreements, if DNCP is unable or unwilling to pay for the power produced by ROVA in a timely manner, it could have a material adverse effect on our results of operations, financial condition, and liquidity.

WMLP also sells a material portion of its coal under supply contracts. For the year ended December 31, 2014, approximately 96.8% of WMLP's coal production was sold under long-term supply contracts. When WMLP’s current contracts with customers expire, its customers may decide not to extend existing contracts or enter into new contracts. In each of 2014 and 2015, 1.7 million tons are to be priced based on market indices, and in each of 2015, 2016 and 2017, 2.1 million tons are dependent upon reaching agreement during reopener periods.

Price adjustment, “price re-opener” and other similar provisions in WMLP’s supply contracts may reduce the protection from short-term coal price volatility traditionally provided by such contracts. Price re-opener provisions typically require the parties to agree on a new price. Failure of the parties to agree on a price under a price re-opener provision can lead to termination of the contract. Any adjustment or renegotiations leading to a significantly lower contract price could adversely affect WMLP’s business, financial condition and/or results of operations.

For the year ended December 31, 2014, WMLP derived 99.1% of its total revenues from coal sales to its 10 largest customers (including their affiliates), with its top three customers (including their affiliates) accounting for 87.5% of such revenues. In the absence of long-term contracts, WMLP’s customers may decide to purchase fewer tons of coal than in the past or on different terms, including different pricing terms. Negotiations to extend existing contracts or enter into new long-term contracts with those and other customers may not be successful, which would negatively affect WMLP’s ability to ~~have sufficient cash to pay distributions~~meet its obligations as they become due and, in turn, would negatively affect our ~~cash flow.~~consolidated results.

Our ~~hedging arrangement in connection~~Buckingham and San Juan mines may subject us to increased regulation and risks associated with ~~the ROVA Consolidated Agreement may~~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 ~~losses if~~more stringent enforcement and possibly the ~~market price for power drops below the level~~passage of ~~our hedged position.~~

~~Under the Consolidated Agreement with respect~~new laws and regulations. Our underground mining operations subject us to ~~our ROVA facility, we expect to forego dispatching the ROVA units in low demand periods~~increased regulatory scrutiny and maintain them in idle status. During such low demand periods, we will meet DNCP’s power needs with fixed-price purchased power if doing so is more economically attractive than our physically operating the ROVA plants to generate power. Alternatively, we have the option to operate the ROVA plants, sell our produced power to DNCP and resell the fixed-price purchased power in the open market. If we choose to operate the ROVA plants and resell our fixed price purchased power into the open market, any such resales would be made at prevailing market rates. In the event that the prevailing market price for power falls below the levelincreased costs of our hedged position during periods when we are reselling the fixed price purchased power in the open market, those resales would result in losses to us. For the year ended December 31, 2014, we incurred losses related to these hedging arrangements of $31.1 million. Based on current market pricing trends, we expect to experience losses from time to time under these hedging arrangements when the market price for power is not commensurate with our hedged position.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

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than the contracted price, or we may be unable to sell the coal at all. Furthermore, the bankruptcy of any of our customers could materially and adversely affect our financial position. In addition, competition with other coal suppliers could cause us to extend credit to customers and on terms that could increase the risk of payment default.

~~In addition,~~ WMLP sells some of its coal to brokers who may resell its coal to end users, including utilities. These coal brokers may have only limited assets, making them less creditworthy than the end users. Under some of these arrangements, WMLP has contractual privity only with the brokers and may not be able to pursue claims against the end users. The bankruptcy or financial deterioration of any of WMLP’s customers, whether an end user or a broker, could ~~adversely~~negatively affect WMLP’s ~~business, financial condition and/or results of operations.~~ability to have sufficient cash to pay distributions and, in turn, would negatively affect our cash flow.

Volatility in the equity markets or interest rate fluctuations could substantially increase our pension funding requirements and negatively impact our financial position.

~~At December 31, 2014, the projected benefit obligation under our defined benefit pension plans was $207.0 million and the fair value of plan assets was $160.9 million.~~ 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. ~~During~~See Note 10 - Pension And Other Saving Plans to the ~~fiscal~~consolidated financial statements for the projected benefit obligation under our defined benefit pension plans at year ~~ended 2014, we made $4.8 million in~~end and the fair value of plan assets. This note also details our contributions to these pension plans and accrued ~~$5.4 million in~~ expenses related ~~thereto.~~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 ~~$306.4~~$332.1 million, ~~$14.0~~$18.2 million and ~~$7.0~~$4.3 million, respectively, at December 31, ~~2014. In respect of our~~2017. Our Canadian ~~Operations we~~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. ~~Our~~See Note 9 - Postretirement Medical Benefits to the consolidated financial statements for our contributions to these funds ~~totaled $2.0 million and $2.2 million for the years ended December 31, 2014 and 2013, respectively. Our contributions to these funds~~which could increase as a result of a shrinking contribution base ~~as a result of~~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"~~Act”). The 2006 Act authorized up to a maximum of $490 million in federal contributions to pay for certain benefits, including the healthcare costs under certain funds created by the Coal Act for “orphans,” i.e. retirees from companies that subsequently ceased operations, and their dependents. However, if Congress were to amend or repeal the 2006 Act or if the $490 million authorization were insufficient to pay for these healthcare costs, we, along with other contributing employers and certain affiliates, would be responsible for the excess costs.

We also contribute to a multi-employer defined benefit pension plan, the Central Pension Fund of the Operating Engineers ("(“Central Pension ~~Fund"~~Fund”), on behalf of employee groups at our ~~Rosebud,~~Colstrip, Absaloka and Savage mines that are represented by the International Union of Operating ~~Engineers.~~Engineers (“IUOE”). The Central Pension Fund is subject to certain funding rules contained in the Pension Protection Act of 2006 ~~("PPA"~~(“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, ~~2014,~~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 ~~were~~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.

~~Through our~~Our Canadian ~~Operations we~~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.

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We are obligated to make contributions to these plans based upon agreement with the plan members and collective bargaining agreements with the representative unions. Our future contributions to these defined benefit plans are made in accordance with applicable pension legislation and the Income Tax Act (Canada). Further contributions to the pension plans could be required based on actuarial valuations, agreements, the plan asset investment performance, and future legislated requirements.

Under Canadian provincial Workers’ Compensation legislation, we remain obligated to fund workers’ compensation benefits arising from workplace injuries, disease and death of current and former employees. This obligation is based on premiums assessed by the applicable Workers’ Compensation Board which may vary based on the claims experience of the employer. We may be required to contribute additional premiums in the future depending on the number and amount of claims.

Our reserve estimates may prove to be incorrect.

The coal reserve estimates in this report are estimates based on the interpretation of limited sampling and subjective judgments regarding the grade, continuity and existence of mineralization, as well as the application of economic assumptions, including assumptions as to operating costs, foreign exchange rates and future commodity prices. The sampling, interpretations or assumptions underlying any reserve estimate may be incorrect, and the impact on the amount of reserves ultimately proven to be recoverable may be material. Should the mineralization and/or configuration of a deposit ultimately turn out to be significantly different from that currently envisaged, then the proposed mining plan may have to be altered in a way that could affect the tonnage and grade of the reserves mined and rates of production and, consequently, could adversely affect the profitability of the mining operations. In addition, short term operating factors relating to the reserves, such as the need for orderly development of ore bodies or the processing of new or different ores, may cause reserve estimates to be modified or operations to be unprofitable in any particular fiscal period. There can be no assurance that our projects or operations will be, or will continue to be, economically viable, that the indicated amount of minerals will be recovered or that they will be recovered at the prices assumed for purposes of estimating reserves.

Any inaccuracies in our estimates of our coal reserves could result in decreased profitability from lower than expected revenues or higher than expected costs.

Our future performance depends on, among other things, the accuracy of our estimates of our proven and probable coal reserves. Our reserve estimates are prepared by our engineers and geologists or by third-party engineering firms and are updated periodically. There are numerous factors and assumptions inherent in estimating the quantities and qualities of, and costs to mine, coal reserves, including many factors beyond our control, including the following:

quality of the ~~coal;~~coal and the percentage of coal ultimately recoverable;

geological and mining conditions, which may not be fully identified by available exploration data and/or may differ from our experiences in areas where we currently mine;

~~the percentage of coal ultimately recoverable;~~

the assumed effects of regulation, including the issuance of required permits, taxes, including severance and excise taxes and royalties, and other payments to governmental agencies;

economic assumptions, including assumptions as to foreign exchange rates and future commodity prices;

assumptions concerning the timing for the development of the reserves; and

assumptions concerning equipment and productivity, future coal prices, operating costs, including for critical supplies such as fuel, tires and explosives, capital expenditures and development and reclamation costs.

~~As a result, estimates~~Estimates of the quantities and qualities of economically recoverable coal attributable to any particular group of properties, classifications of reserves based on risk of recovery, estimated cost of production, and estimates of future net cash flows expected from these properties may vary materially due to changes in the above factors and assumptions. ~~Any inaccuracy~~Inaccuracies in our reserve estimates ~~related to our reserves~~ could result in decreased profitability from lower than expected revenues or higher than expected costs.

If the assumptions underlying our reclamation and mine closure obligations are materially inaccurate, we could be required

to expend greater amounts than anticipated.

We are subject to stringent reclamation and closure standards for our mining operations. We calculated the total estimated reclamation and mine-closing liabilities according to the guidance provided by GAAP and current industry practice. Estimates of our total reclamation and mine-closing liabilities are based upon permit requirements and our engineering expertise related to these requirements. If our estimates are incorrect, we could be required in future periods to spend materially different amounts on reclamation and mine-closing activities than we currently estimate. Likewise, if our customers, some of

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whom are contractually obligated to pay certain reclamation costs, default on the unfunded portion of their contractual obligations to pay for reclamation, we could be forced to make these expenditures ourselves and the cost of reclamation could exceed any amount we might recover in litigation.

~~We estimate that~~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, were $452.7 million (on a present value basis) at December 31, 2014. Of these December 31, 2014 liabilities, our customers have assumed $116.5 million by contract. In addition, we held finalexperience. The note details reclamation deposits held by us and received from customers ~~of approximately $77.9 million at December 31, 2014~~ to provide for these obligations. ~~We estimate that~~The note also shows our estimated obligation for final reclamation that was not the contractual responsibility of others or covered by offsetting reclamation deposits ~~was $261.0 million at December 31, 2014. We~~and how much we must recover ~~this $261.0 million~~ from revenues ~~generated by coal sales.~~

to fund this deficit. Although we update our estimated costs annually, our recorded obligations may prove to be inadequate due to changes in legislation or standards and the emergence of new restoration techniques. Furthermore, the expected timing of expenditures could change significantly due to changes in commodity costs or prices that might curtail the life of an operation. These recorded obligations could prove insufficient compared to the actual cost of reclamation. Any underestimated or unidentified close down, restoration or environmental rehabilitation costs could have an adverse effect on our reputation as well as our asset values, results of operations and liquidity.

If the cost of obtaining new reclamation bonds and renewing existing reclamation bonds increases or if we are unable to obtain additional bonding capacity, our operating results could be negatively affected.

We are required to provide bonds to secure our obligations to reclaim lands used for mining. We must post a bond before we obtain a permit to mine any new area. These bonds are typically renewable on a yearly basis. Bonding companies ~~are requiring~~require that applicants collateralize ~~increasing~~ portions of their obligations to the bonding company. ~~We anticipate that, as~~In 2017, we ~~permit additional areas for~~paid approximately $11.0 million in premiums and fees related to our ~~mines, our~~reclamation bonds. If the bonding ~~and~~premium or collateral requirements ~~could increase. Any~~increase, any cash that we provide to collateralize our obligations to our bonding companies is not available to support our other business ~~activities. Our~~activities and our results of operations could be negatively ~~affected if the cost of our reclamation bonding premiums and collateral requirements were to increase.~~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 ~~our recently acquired~~the Buckingham ~~Mine,~~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 ~~other~~ natural gas and other resource extraction activities and production within our operating areas. For example, ~~in our recent past,~~ we have endured poor rail performance at the Absaloka ~~Mine,~~ and Coal Valley ~~Mine, a major blizzard~~mines, unprecedented rain at the ~~Beulah Mine, a trestle fire at the Beulah Mine,~~Kemmerer mine, and an unanticipated ~~replacement~~maintenance of ~~boom suspension cables on one~~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 of December 31, 2014, six of our 30 owned or operated draglines were not in use due to either equipment servicing or because the dragline was scheduled to be down based on the operational needs of our mines. If properly maintained, a dragline can operate for 40 years or longer. As of December 31, 2014, the average age of Westmoreland’s dragline fleet was 34 years. In addition, at our Kemmerer Mine we use shovels instead of draglines. If properly maintained, a shovel can last for 30 years or longer. As of December 31, 2014, the average age of our shovels was 17 years. As our draglines, shovels and other major equipment ~~ages,~~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~~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, ~~in November 2011,~~ the ~~Sherburne County station~~Conesville power plant, which is the largest customer of our Buckingham mine, experienced an ~~explosion~~unexpected shutdown in the first and ~~fire that~~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 ~~an extended outage. As~~by a ~~result,~~

~~Table~~malfunctioning fan in one of ~~Contents~~the units. The Conesville

~~we lost approximately 50% of our coal sales~~plant ran at half its capacity until the necessary repairs were completed in 2012 and 2013 at our Absaloka Mine. While the Sherburne County station initially indicated a start-up date of March 2013, it did not ultimately resume operations until October 2013, resulting in additional lost coal sales during 2013.early December 2015. We maintain business interruption insurance coverage at some of our mines to lessen the impact of events such as this, and have received a total of approximately $33.6 million of cash proceeds in insurance compensation for lost sales to the Sherburne County station. While we believe our insurance did not fully compensate us for the impact of lost sales, we believe the shortfall was not material.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.~~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. ~~Although we maintain insurance at levels we believe are appropriate and consistent with industry practice, we are not fully insured against all risks. In addition, pollution~~Pollution and environmental risks and consequences of any business interruptions such as equipment failure or labor disputes generally are not fully insurable. Losses and liabilities from uninsured and underinsured events and delay in the payment of insurance proceeds could have a material adverse effect on our financial condition, results of operations and cash flows.

Mining ~~in Northern Appalachia and the Illinois Basin~~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.

~~Long-term sales and revenues could be significantly affected by environmental regulations and the effects of the environmental lobby.~~

Environmental regulations that are becoming increasingly stringent, as well as increased pressure from environmental activists, may reduce demand for our products. For example, a consortium of environmental activists is actively pushing to shut down one-third of the nation’s coal plants by 2020. They are taking particular interest in Colstrip Units 1 and 2 and are actively lobbying the EPA to require cost-prohibitive pollution control equipment. In litigation filed in 2012, the activists stated that the EPA’s Best Available Retrofit Technology (“BART”) analysis for regional haze provides support for a determination that additional controls are necessary to achieve BART. A decision in the case is pending. In 2013, environmental groups also filed a citizen suit complaint in Montana district court asserting that the owners and operators of Colstrip are in violation of Clean Air Act requirements. Trial in the case has been reset for August 2015. If environmental groups are successful, Colstrip would be required to undergo new permitting and comply with more stringent emission limits applicable to a number of pollutants. If additional emissions controls and upgrades are required at Colstrip Units 1 and 2, it is possible the owners could elect to shut down the units in lieu of making the large capital expenditures required to comply. If such a decision were made, we could lose coal sales of approximately 3.0 million tons per year. The loss of the sale of this tonnage at our Rosebud Mine could have a material adverse effect on the mine’s revenues and profitability.

Additionally, Rocky Mountain Power, the owner of the Naughton Power Station located adjacent to our Kemmerer Mine, which is our Kemmerer Mine’s primary customer, has sought regulatory approval to convert Unit 3 at Naughton to 100% natural gas fueling. When complete, the conversion of Unit 3 to natural gas will result in the loss of coal sales at our Kemmerer Mine. However, Rocky Mountain Power recently announced the conversion of Naughton Unit 3 will not occur until 2018. In addition, price protections built into the contract that are in effect from 2017 to 2021 will partially offset the effects of lowered

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volume following the conversion of Unit 3. Despite these price protections, the lost sales at the Kemmerer Mine could have a material adverse effect on the mine’s revenues and profitability and on our operating results. Additional power plants that buy our coal may be considering or may consider in the future fuel source conversion or decreased operations in order to avoid costly upgrades of pollution control equipment, and such steps, if taken, could result in a reduced demand for our products and materially and adversely affect our revenues and profitability.

The EPA and the U.S. Army Corps of Engineers have proposed a rule to clarify which waters and wetlands are subject to regulation under the CWA. A change in CWA jurisdiction and permitting requirements could increase or decrease our permitting and compliance costs.

The EPA has executed a final rule relating to the disposal of CCR from electric utilities. The changes to the management of CCR could increase our and our customers’ operating costs and reduce sales of coal.

We are also affected by Canadian GHG emissions regulations. On September 12, 2012, the federal government of Canada released final regulations for reducing GHG emissions from coal-fired electricity generation: “Reduction of Carbon Dioxide Emissions from Coal-Fired Generation of Electricity” (the “Canadian CO2 Regulations”). The Canadian CO2 Regulations will require certain Canadian coal-fired electricity generating plants, effective July 1, 2015, to achieve an average annual emissions intensity performance standard of 420 tons of CO2 per gigawatt hour. The impact of the Canadian CO2 Regulations on existing plants will vary by province and specific location. PMRU’s long-term sales could be reduced unless certain existing plants that it supplies or new plants built to replace such existing plants are equipped with carbon capture and sequestration or other technology that achieves the prescribed performance standard, the impact of the Canadian CO2 Regulations is altered by equivalency agreements, or the Canadian CO2 Regulations are changed to lower the performance standard.

In addition, various Canadian provincial governments and other regional initiatives are moving ahead with GHG reduction and other initiatives designed to address climate change. As it is unclear at this time what shape additional regulation in Canada will ultimately take, it is not yet possible to reliably estimate the extent to which such regulations will impact the operations we acquired in the Canadian Acquisition. However, our Canadian Operations involve large facilities, so the setting 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.

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 Absaloka Mine benefited from Indian Coal Production Tax Credits, the permanent loss of which will adversely affect the financial condition of the operation.~~

The ICTC, which our Absaloka Mine historically benefited from, expired on December 31, 2014. There is no assurance that a renewal, if any is enacted, would be enacted with retroactive effect. The provisions regarding any future renewal may not be as favorable as those that previously existed. Additionally, the investment in Absaloka by our partner did not continue after December 31, 2013. We expect to seek a new partner in the event of a future renewal, but our results of operations will continue to be negatively affected during the interim period and for any period for which the ICTC is not renewed with retroactive effect. From 2009 through 2013, we experienced a yearly average of $3.1 million of income and $6.1 million of cash receipts from Absaloka’s participation in ICTC transactions.

Our future success depends upon our ability to continue acquiring and developing coal reserves through acquisition that are economically recoverable and to raise the capital necessary to fund our expansion.

Our ~~recoverable~~ reserves decline as we produce coal. We have not yet applied for the permits to use all of the coal deposits under our mineral rights, and the government agencies may not grant those permits in a timely manner or at all. Furthermore, we may not be able to mine all of our coal deposits as efficiently as we do at our current operations. Our future success depends upon conducting successful exploration and development activities and acquiring properties containing economically recoverable coal deposits. Our current strategy includes increasing our coal reserves through acquisitions of other mineral rights, leases, or producing properties and continuing to use our existing properties. Our ability to expand our operations may be dependent on our ability to obtain sufficient working capital, either through cash flows generated from operations, or financing activities, or both. As we mine our coal and deplete our existing reserves, replacement reserves may not be available when required or, if available, we may not be capable of mining the coal at costs comparable to those characteristic of the depleting mines. These factors could have a material adverse effect on our mining operations and costs, and our customers’ ability to use the coal we mine.

~~We may not be able to successfully replace our reserves or grow through future acquisitions.~~

In recent years, we have expanded our operations by adding new mines and reserves through strategic acquisitions, and we intend to continue expanding our operations and coal reserves through additional future acquisitions. Our future growth could be limited if we are unable to continue making acquisitions, or if we are unable to successfully integrate the companies, businesses or properties we acquire. We may not be successful in consummating any acquisitions and the consequences of undertaking these acquisitions are unknown. Our ability to make acquisitions in the future could be limited by restrictions under our existing or future debt agreements, competition from other coal companies for attractive properties or the lack of suitable acquisition candidates.

Our cash flow depends, in part, on the available cash and distributions of WMLP, 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:

restrictions contained in the debt agreements to which it is a party;

the domestic and foreign supply and demand for coal;

the quantity and quality of coal available from competitors;

the prices under WMLP’s existing contracts where the pricing is tied to and adjusted periodically based on indices reflecting current market pricing;

competition for production of electricity from non-coal sources, including the price and availability of alternative fuels;

domestic air emission standards for coal-fueled power plants and the ability of coal-fueled power plants to meet these standards by installing scrubbers or other means;

adverse weather, climate or other natural conditions, including natural disasters;

domestic and foreign taxes;

domestic and foreign economic conditions, including economic slowdowns;

legislative, regulatory and judicial developments, environmental regulatory changes or changes in energy policy and energy conservation measures that would adversely affect the coal industry, such as legislation limiting carbon emissions or providing for increased funding and incentives for alternative energy sources;

the proximity to, capacity of and cost of transportation and port facilities;

market price fluctuations for sulfur dioxide emission allowances;

the level of capital expenditures it makes;

the cost of acquisitions;

its debt service requirements and other liabilities;

fluctuations in its working capital needs;

its ability to borrow funds and access the capital markets; and

the amount of cash reserves established by its general partner.

Any adverse change in these and other factors could result in a decline in WMLP’s ability to have sufficient cash to pay distributions and, in turn, would negatively affect our cash flow. 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.

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 Note17. 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:

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

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~~mine and our Coal Valley ~~Mine~~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,~~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~~mine exports the majority of its production to the global seaborne market through a port ~~facilities~~facility in western Canada.

The unavailability of rail capacity and port capacity could also hinder our future growth as we seek to sell coal into new markets. The current availability of rail cars is limited and at times unavailable because of repairs or improvements, or because of priority transportation agreements with other customers. Port capacity is also restricted in certain markets. If transportation is restricted or is unavailable, we may be unable to sell into new markets and, therefore, the lack of rail or port capacity would hamper our future growth. We currently have sufficient committed port capacity to operate our export business, and additional port capacity is expected to be constructed in western Canada in the future. However, increases in transportation costs or the lack of sufficient rail or port capacity or availability could make our coal less competitive, or could result in coal becoming a less competitive source of energy in general, which could lead to reduced coal sales and/or reduced prices we receive for the coal. Our inability to timely deliver product or fuel switching due to rising transportation costs could have a material adverse effect on our business, financial condition and results of operations.

In addition, WMLP depends upon barge, rail and truck systems to deliver coal to its customers. Disruptions in transportation services due to weather-related problems, mechanical difficulties, strikes, lockouts, bottlenecks, and other events could impair WMLP’s ability to supply coal to its customers. ~~In recent years, the Commonwealth of Kentucky and the State of West Virginia~~Certain states have increased enforcement of weight limits on coal trucks on their public roads. It is possible that all states in

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which WMLP’s coal is transported by truck may modify their laws to limit truck weight limits. Such legislation and enforcement efforts could result in shipment delays and increased costs, which could have an adverse effect on WMLP’s ability to increase or to maintain production and could adversely affect its revenues.

Decreased availability or increased costs of key equipment and materials could impact our cost of production and decrease our profitability.

We depend on reliable supplies of mining equipment, replacement parts and materials such as explosives, diesel fuel, tires and magnetite. The supplier base providing mining materials and equipment has been relatively consistent in recent years, although there continues to be consolidation, which has resulted in a limited number of suppliers for certain types of equipment and supplies. Any significant reduction in availability or increase in cost of any mining equipment or key supplies could adversely affect our operations and increase our costs, which could adversely affect our operating results and cash flows.

In addition, the prices we pay for these materials are strongly influenced by the global commodities market. Coal mines consume large quantities of commodities such as steel, copper, rubber products, explosives, ~~and~~ diesel and other liquid fuels. Some materials, such as steel, are needed to comply with regulatory requirements. A rapid or significant increase in the cost of these commodities could increase our mining costs because we have limited ability to negotiate lower prices, and in some cases, do not have a ready substitute.

~~Our~~Certain of our long-term coal contracts are ~~"cost protected"~~“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,~~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 ~~mineral titles~~permits and licenses in certain Canadian provinces may be affected by aboriginal ~~rights, and such rights may give rise to claims that compete with or impair our title to certain of our Canadian properties.~~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 ~~mineral rights~~ and the issuance or amendment of project authorizations, including approvals, permits and licenses. These requirements may affect the ability of our Canadian ~~Subsidiaries~~operations to acquire ~~effective mineral titles~~new or amended operating approvals in these jurisdictions within a reasonable time frame, and may affect our development schedule and ~~costs of mineral properties. Additionally, the risk of unforeseen aboriginal title claims could compete with or impair some or all of our Canadian Operations~~costs.

Union represented labor creates an increased risk of work stoppages and higher labor costs.

As of December 31, ~~2014,~~2017, approximately 60% of our total ~~U.S.~~ workforce is represented by ~~two~~three labor unions, the IUOE, the International ~~Union~~Brotherhood of ~~Operating Engineers~~Electrical Workers and the UMWA. Our unionized workforce is spread out amongst the majority of our surface ~~mines.~~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. ~~The collective bargaining agreement relating~~

Congress has proposed legislation to enact a law allowing workers to choose union representation solely by signing election cards, which would eliminate the ~~represented workforce at~~use of secret ballots to elect union representation. While the ~~Absaloka Mine will expire on May 31, 2015. In 2012, we were successful in entering~~impact is uncertain, if the government enacts this proposal into ~~agreements with our workforce at Savage, Kemmerer and Rosebud. If our Jewett Mine operations were~~law, which would make it administratively easier to ~~become unionized, we could be subject~~unionize, it may lead to additional risk of work stoppages, other labor disputes and higher labor costs, which could adversely affect the stability of production and our results of operations. We reached an with the UMWA in December 2014 on a new collective bargaining agreement at the Beulah Mine to replace the existing agreement which expires on January 1, 2015.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.

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

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~~the government enacts this proposal into law, which would make it administratively easier to unionize, it may lead to more coal mines becoming unionized.~~

As of December 31, 2014, approximately 69% of our total Canadian workforce was represented by a labor union. There are labor agreements in place with one or more unions at each of the producing mines we acquired in the Canadian Acquisition, other than the Genesee Mine. Our collective bargaining agreement related to the Estevan Mine will expire on June 30, 2015. If we are not successful in negotiating new labor agreements as they expire with any of the Canadian workforce unions or otherwise maintaining strong partnerships with them, it could result in labor disputes, work stoppages or higher labor costs, any of which could have an adverse effect on our business and results of operations.

Currently, none of WMLP’s employees is represented under collective bargaining agreements. However, all of its workforce may not remain union-free in the future. If some or all of WMLP’s workforce were to become unionized, it could adversely affect its productivity and labor costs and increase the risk of work stoppages, all of which could adversely affect WMLP’s business, financial condition and/or results of operations.

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 ~~Acquisition,~~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 ~~Acquisition,~~mines, we face increased exposure to exchange rate fluctuations between the Canadian dollar and U.S. dollar. We realize a large portion of our revenues from sales made from the Canadian assets in Canadian dollars, and almost all of the expenses incurred by the Canadian assets are recognized in Canadian dollars. The exchange rate of the Canadian dollar to the U.S. dollar has been at or near historic highs in recent years, ~~but~~settled at a relatively

weak position during 2016 and recovered slightly in ~~the last quarter of 2014 and first quarter of 2015 has weakened considerably.~~2017. If ~~this weakening of~~ the Canadian dollar remains weak in comparison to the U.S. dollar, ~~continues,~~ earnings generated from our Canadian ~~Operations~~operations will translate into reduced earnings in ~~our consolidated statements~~the Consolidated Statements of ~~operations~~Operations reported in U.S. dollars. In addition, our Canadian ~~Subsidiaries also~~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~~operations will be translated using period-end exchange rates, and the revenues and expenses of our Canadian ~~Operations~~operations will be translated using average exchange rates during each period. Translation gains and losses are reported in accumulated other comprehensive loss as a component of stockholders’ equity.

Federal legislation could result in higher healthcare costs.

In March 2010, the Patient Protection and Affordable Care Act (the “PPACA”) was enacted, impacting our costs of providing healthcare benefits to our eligible active employees, with both short-term and long-term implications. In the short term, our healthcare costs could increase due to, among other things, an increase in the maximum age for covered dependents to receive benefits, changes to benefits for occupational disease related illnesses, the elimination of lifetime dollar limits per covered individual and restrictions on annual dollar limits per covered individual. In the long term, our healthcare costs could increase for these same reasons, as well as due to an excise tax on “high cost” plans, among other things. ~~Implementation~~However, implementation of this ~~legislation is expected to extend through 2018.~~

~~Beginning in 2018, the PPACA will~~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.~~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.

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~~Certain federal income tax preferences currently available with respect to coal exploration and development may be eliminated in future legislation.~~

Among the changes contained in President Obama’s budget proposal (the “Budget Proposal”) is the elimination of certain key U.S. federal income tax preferences relating to coal exploration and development. The Budget Proposal would: (i) eliminate current deductions, the 60-month amortization period and the 10-year amortization period for exploration and development costs relating to coal and other hard mineral fossil fuels, (ii) repeal the percentage depletion allowance with respect to coal properties, (iii) repeal capital gains treatment of coal and lignite royalties and (iv) exclude from the definition of domestic production gross receipts all gross receipts derived from the production of coal and other hard mineral fossil fuels. The passage of any legislation effecting changes similar to those in the Budget Proposal in U.S. federal income tax laws could eliminate certain tax deductions that are currently available with respect to coal exploration and development, and any such change could increase our taxable income and negatively impact the value of an investment in our common stock.

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 ~~2014,~~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. ~~We do not have~~Though certain of our contracts ~~guaranteeing~~contain take or pay provisions, only some of our contracts guarantee the purchase of fixed quantities of coal soand, as a result, in certain economic environments revenue can fall ~~even though we have~~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

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.

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Changes in the export and import markets for coal products could affect the demand for our coal, our pricing and our profitability.

Although our mines and the majority of our customers are located in North America, we compete in a worldwide market for coal and coal products. The pricing and demand for our products is affected by a number of global economic factors that are beyond our control and difficult to predict. These factors include:

currency exchange rates;

growth of economic development;

price of alternative sources of electricity or steel;

worldwide demand for coal and other sources of energy; and

ocean freight rates.

Any decrease in the aggregate amount of coal exported from the United States and Canada, or any increase in the aggregate amount of coal imported into the United States and Canada, could have a material adverse impact on the demand for our coal, our pricing and our profitability. Ongoing uncertainty in European economies and slowing economies in China, India and Brazil have reduced and may continue to reduce near-term pricing and demand for coal exported from the United States and Canada. The Coal Valley ~~Mine~~mine primarily supplies premium thermal coal to the Asian export market. Ownership of this mine will increase our exposure to price fluctuations in the international coal market, and a substantial downturn in demand in the Asian market could have a material adverse effect on our financial condition and results of operations.

Extensive government regulations impose significant costs on our mining operations, and future regulations could increase those costs or limit our ability to produce and sell coal.

The coal mining industry is subject to increasingly strict regulation by federal, state and local authorities with respect to matters such as:

limitations on land use;

employee health and safety;

mandated benefits for retired coal miners;

mine permitting and licensing requirements;

reclamation and restoration of mining properties after mining is completed;

air quality standards;

discharges to water;

construction and permitting of facilities required for mining operations, including valley fills and other structures constructed in water bodies and wetlands;

protection of human health, plant life and wildlife;

management of the materials generated by mining operations and discharge of these materials into the environment;

effects of mining on groundwater quality and availability; and

remediation of contaminated soil, surface and groundwater.

We are required to prepare and present to governmental authorities data concerning the potential effects of any proposed exploration or production of coal on the environment and the public has statutory rights to submit objections to

requested permits and approvals. Failure to comply with MSHA regulations may result in the assessment of administrative, civil and criminal penalties. Other governmental agencies may impose cleanup and site restoration costs and liens, issue injunctions to limit or cease operations, suspend or revoke permits and take other enforcement measures that could have the effect of limiting production from our operations. We may also incur costs and liabilities resulting from claims for damages to property or injury to persons arising from our operations. We must compensate employees for work-related injuries. If we do not make adequate provision for our workers’ compensation liabilities, it could harm our future operating results. If we are pursued for any sanctions, costs and liabilities, our mining operations and, as a result, our results of operations, could be adversely affected.

United States and Canadian federal, state or provincial regulatory agencies have the authority to temporarily or permanently close a mine following significant health and safety incidents, such as a fatality. In the event that these agencies order the closing of our mines, our coal sales contracts may permit us to issue force majeure notices which suspend our obligations to deliver coal under these contracts. However, our customers may challenge our issuances of force majeure notices. If these challenges are successful, we may have to purchase coal from third-party sources, if it is available, and

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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 ~~“U.S. and Canadian Coal Segment~~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 ~~in,~~ and in some cases enactment of, laws and regulations governing greenhouse gas emissions, which affect the end-users of coal and could reduce the demand for coal as a fuel source and cause the volume of our sales and/or the prices we receive to decline. These laws and regulations also have imposed, and will continue to impose, costs directly on us.

GHG emissions have increasingly become the subject of international, national, state, provincial and local attention. Coal-fired power plants can generate large amounts of GHG emissions. Accordingly, legislation or regulation intended to limit GHGs will likely indirectly affect our coal operations by limiting our customers’ demand for our products or reducing the prices we can obtain, and also may directly affect our own power operations. In the United States, the EPA, has issued a determination that emissions of carbon dioxide, methane, nitrous oxide and other GHGs present an endangerment to human health and the environment, which allows the EPA to begin regulating emissions of GHGsacting under existing provisions of the federal Clean Air ~~Act. The EPA implemented~~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 ~~recently~~ 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~~Obama’s Climate Action Plan announced in June 2013, ~~announced a Climate Action Plan, which included a Presidential Memorandum directing~~ the EPA ~~to issue~~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 EPA issued a revised proposal with standards for new fossil fuel-fired plants, including coal-fired plants, in September 2013, which the EPA plans to finalize by January 2015. The EPA also has released its “Clean Power Plan” in June 2014, which includes proposed standards for existing and modified sources. Under the Clean Power Plan ~~as currently proposed, the EPA would set~~sets standards for existing sources as stringent state-specific carbon emission rates ~~that, if finalized, would~~to be phased in between 2020 and 2030. The ~~proposed~~ rule would give states the discretion to use a variety of approaches - including cap-and-trade programs - to meet the standard. ~~The EPA estimates that~~In February of 2016, however, the ~~proposed existing source rule would reduce CO2 emissions from~~Supreme Court issued an order staying the ~~power sector by 30 percent by 2030, with a focus on emissions from coal-fired generation. The EPA plans to finalize~~Clean Power Plan pending judicial review of the rule by ~~June 2015, with state plans due~~the U.S. Court of Appeals for the D.C. Circuit as well as potential review by ~~June 2016, with one-~~the Supreme Court. The D.C. Circuit issued an expedited briefing schedule for challenges to ~~two-year extensions available.~~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 ~~U.S. Congress has considered, and~~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 ~~future may again consider, legislation governing~~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 ~~including “cap~~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 trade” legislation that would establish a cap on emissions of GHGs covering much of the economy in the United States and would require most sources of GHG emissions to obtain GHG emission “allowances” corresponding to their annual emissions of GHGs.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 ~~proposed~~ rules would have on our revenues and profitability. For additional information, see ~~“Business~~Item 1 - Business -

Material Effects of ~~Regulation” in this report.~~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~~CO₂ Regulations. The Canadian ~~CO2~~CO₂ Regulations ~~will require~~required certain Canadian coal-fired electricity generating units, effective July 1, 2015, to achieve an average annual emissions intensity performance standard of ~~420~~463 tons of ~~CO2~~CO₂ per gigawatt hour. ~~This performance standard represents approximately one-half of the annual average CO2 emissions intensity of the customer generating assets currently served by the Prairie operations.~~ The performance standard ~~will apply~~applies to new units commissioned after July 1, 2015 and to units that are considered to have reached the end of their useful life ~~generally between 45 and~~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~~CO₂ Regulations would stand down, are being negotiated or discussed with the provinces of Alberta and Saskatchewan. The ~~Prairie~~Canadian coal production in the long-term could be reduced unless certain existing units or new units of the customers served by the ~~Prairie operations~~Canadian mines are equipped with carbon capture and storage or other technology that achieves the prescribed performance standard, the impact of the Canadian ~~CO2~~CO₂ Regulations is altered by equivalency agreements, or the Canadian ~~CO2~~CO₂ Regulations are changed to lower the performance standard. The impact of the Canadian ~~CO2~~CO₂ Regulations on existing units will vary by location and province.

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~~In addition, various~~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 “CCEM”),~~ the Province of Alberta enacted the “Specified Gas Emitters ~~Regulation.”~~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 ~~2013~~2016 compliance period, Coal Valley ~~Mine exceeded the 100,000 ton emissions threshold established under the Specified Gas Emitters Regulation, and Coal Valley Mine~~mine was not required to ~~contribute to the Climate Change and Emissions Management Fund.~~purchase fund credits. For the ~~2014~~2017 compliance period, the ~~preliminary~~ calculations indicate that the Coal Valley ~~Mine~~mine will be required to purchase fund credits. ~~It is anticipated that for the next several years, emissions intensity at Coal Valley Mine will increase as the distance between the coal being mined and the processing plant increases.~~ The Government of Alberta has also introduced a complementary Specified Gas Reporting Regulation, which came into force on October 20, 2004. This legislation requires all industrial emitters emitting ~~50,000 tons~~10,000 tonnes or more of ~~CO2~~specified gases to report their annual ~~GHG~~ emissions in accordance with the specified Gas Reporting Standard published by the Government of Alberta. In Saskatchewan, Bill 126, The Management and Reduction of Greenhouse Gases Act, was passed in 2010 but ~~is not yet~~only limited sections have been proclaimed in force. The legislation provides a framework for the control of GHG emissions by regulated emitters and ~~will~~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. For example, the Naughton power facility, which is located adjacent to the Kemmerer Mine, announced in April 2012 that it is seeking regulatory approval to switch Unit 3 to natural gas from coal. The conversion of Naughton Unit 3 to natural gas would result in significant reduction in coal sales from our Kemmerer Mine, and could have a material adverse effect on our results of operations. However, Rocky Mountain Power, the owner of the Naughton facility, recently announced that the conversion will not take place until at least 2018.

Political opposition to the development of new coal-fired power plants, or regulatory uncertainty regarding future emissions controls, may result in fewer such plants being built, which would limit our ability to grow in the future.

In addition to directly emitting GHGs, our Canadian Operations require large quantities of power. Future taxes on or regulation of power producers or the production of coal, oil and gas or other products may also add to our operating costs. ~~And many~~The policy recommendations put forward by the Alberta Climate Leadership Panel, if enacted, have the potential to increase costs of ~~the developments~~energy products used in the ~~U.S. discussed above that may affect our customers~~mine operations located in Alberta, such as diesel fuel, gasoline, oil, and ~~demand for our coal could also affect us directly through adverse impacts on ROVA~~electricity.

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. ~~The slowing pace at which permits are issued or renewed for new and existing mines has materially impacted production in Appalachia, but could also affect other regions in which WMLP operates.~~ An inability to obtain the necessary permits to conduct WMLP’s mining operations or an inability to comply with the requirements of applicable permits could reduce WMLP’s production and cash flows, which could adversely affect its business, financial condition and/or results of operations and our cash flow.

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Extensive environmental laws, including existing and potential future legislation, treaties and regulatory requirements relating to air emissions other than GHGs, affect our customers and could reduce the demand for coal as a fuel source and cause coal prices and sales of our coal to materially ~~decline, and could impose additional costs on ROVA.~~decline.

Our customers ~~as well as ROVA,~~ are subject to extensive environmental regulations particularly with respect to air emissions other than GHG. Coal contains impurities, including but not limited to sulfur, mercury, chlorine and other elements or compounds, many of which are released into the air when coal is burned. The emission of these and other substances is extensively regulated at the federal, state, provincial and local level, and these regulations significantly affect our customers’ ability to use the coal we produce and, therefore, the demand for that coal. For example, the purchaser of coal produced from the Jewett Mine blends our lignite with compliance coal from Wyoming. Tightened nitrogen oxide and new mercury emission standards could result in the customer purchasing an increased blend of the Wyoming coal in order to reduce emissions. Further, increased market prices for sulfur dioxide emissions allowances and increased coal ash management costs could also favor an increased blend of the lower ash Wyoming compliance coal. In such a case, the customer has the option to increase its purchases of other coal and reduce purchases of our coal or terminate our contract. A termination of the contract or a significant reduction in the amount of our coal that is purchased by the customer could have a material adverse effect on our results of operations and financial condition.

The EPA ~~intends to issue or~~ has issued a number of significant regulations ~~that will~~to impose more stringent requirements relating to air, water and waste controls on electric generating units. ~~These rules include the EPA’s executed new final rule for CCR management that further regulates the handling~~For more details, see Item 1 - Business - Material Effects of wastes from the combustion of coal. In addition, in February 2012, the EPA signed a rule to reduce emissions of mercury and toxic air pollutants from new and existing coal- and oil-fired electric utility steam generating units, often referred to as the MATS Rule. This rule was upheld by the U.S. Court of Appeals for the D.C. Circuit in April 2014. In April 2014, the U.S. Supreme Court upheld the EPA’s Cross-State Air Pollution Rule (“CSAPR”), which would require stringent reductions in emissions of nitrogen oxides and sulfur dioxide from power plants in much of the Eastern United States, including Texas and North Carolina, and in October 2014 the D. C. Circuit granted the EPA’s motion to lift the D.C. Circuit’s stay of the CSAPR, and remanded the case to the D.C. Circuit for further proceedings, which are ongoing. The EPA issued an interim rule in December 2014 that would require the first phase of reductions in 2015 and 2016, with the second phase of reductions beginning in 2017. In May 2014, the EPA Administrator signed a final rule that establishes requirements for cooling water intake structures for the withdrawal of cooling water by electric generating plants; the rule is anticipated to affect over 500 power plants.Regulation.

Considerable uncertainty is associated with air emissions ~~initiatives.~~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 ~~either~~already in place, ~~or are likely to be imposed in the short to medium term,~~ and these limitations will likely require significant emissions control expenditures for many coal-fired power plants. For example, the owners of Units 3 ~~and~~& 4, ~~at Colstrip,~~ adjacent to our ~~Rosebud Mine,~~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 ~~Acquisition.~~mines. Specifically, the Alberta ~~Environmental Protection~~Climate Change and ~~Enhancement~~Emissions Management Act, 2003 (“~~EPEA”~~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 ~~EPEA~~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,

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encouraging voluntary action to reduce releases, tracking the progress of reductions in releases, improving public awareness and understanding of substances released into the environment, and supporting targeted initiatives for regulating the release of substances.

Regulatory authorities can enforce these and other environmental laws through administrative orders to control, prevent or stop a certain activity; administrative penalties for violating certain environmental laws; and judicial proceedings. If environmental regulatory burdens continue to increase for our Canadian customers, as a result of policy changes or increased regulatory reform relating to the substances reported, it could potentially affect customer operations and ~~future~~ demand for coal.

Risk Factors Relating to our Equity

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, ~~and~~ 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.

Provisions in our certificate of incorporation, bylaws and Delaware law could make it more difficult for a third party to acquire us, even if doing so might be beneficial to our stockholders. Provisions of our bylaws impose various procedural and other requirements that could make it more difficult for stockholders to bring about some types of corporate actions such as electing individuals to the board of directors. Our ability to issue preferred stock in the future may influence the willingness of an investor to seek to acquire our company. ~~These~~

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 ~~Our~~ Acquisitions

We may not have uncovered all risks associated with our acquisition of the Canadian Subsidiaries, our controlling interest in WMLP or Buckingham (collectively, the “Acquisitions”) and significant liabilities of whichThe assets we ~~are not aware may exist now or arise~~acquired in the ~~future.~~

Upon consummation of the Acquisitions, 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 the Acquisitions or for costs associated with known liabilities that exceed our estimates. Under the various purchase arrangement for relating to the Acquisitions, there may or may not be recourse to indemnification should we discover a previously unknown liability, whether material or immaterial.

~~WMLP~~San Juan Acquisition may underperform relative to our ~~expectations, causing~~expectations; the San Juan Acquisition may cause our financial results to differ from our expectations or the expectations of the investment ~~community,~~community; and we may not be able to achieve anticipated cost savings or other anticipated ~~objectives of our acquisition of the GP.~~objectives.

The success of the ~~WMLP transactions~~San Juan Acquisition will depend, in part, on our ability to ~~realize~~integrate the ~~anticipated growth opportunities~~San Juan Entities with our existing business. The integration process may be complex, costly and ~~operating efficiencies, which we influence as the owner of the GP.~~time consuming. The potential ~~obstacles to~~difficulties of integrating the San Juan Entities and realizing our expectations for the ~~WMLP transactions~~San Juan Acquisition include, among other things:

failure to implement our strategy for the development ~~and streamlining~~ of ~~WMLP’s business;~~

~~failure to implement our dropdown strategy to transfer certain strategic assets or operations to WMLP in~~ the ~~future;~~acquired assets;

unanticipated changes in commodity prices;

unanticipated changes in applicable laws and regulations;

retaining and obtaining required regulatory approvals, licenses and permits;

operating risks inherent in our business; and

other unanticipated issues, expenses and liabilities.

Many of these factors will be outside of our control, and any one of them could result in increased costs, decreases in the amount of expected revenues and diversion of management’s time and energy, which could materially impact our business, 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.

~~Our cash flow depends,~~SJCC is subject to pending litigation that could result in ~~part,~~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 ~~available cash~~United States District Court for the District of Colorado seeking review of the Office of Surface Mining (“OSM”) decisions and ~~distributions~~decisions of ~~WMLP.~~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 expect our partnership interests in WMLP to be significant cash-generating assets. Therefore, our cash flow will be dependent, to some extent, upon the ability of WMLP to make quarterly distributions to its unitholders, including us. WMLP

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may not have ~~sufficient available cash each quarter~~uncovered all risks associated with our acquisition activity, and significant liabilities related to ~~enable it to pay distributions,~~such activity of which would have a corresponding negative impact on us. The amount of cash WMLP can distribute on its units principally depends upon the amount of cash it generates from its operations, which will fluctuate from quarter to quarter based on, among other things:

~~the domestic and foreign supply and demand for coal;~~

~~the quantity and quality of coal available from competitors;~~

~~the prices under WMLP’s existing contracts where the pricing is tied to and adjusted periodically based on indices reflecting current market pricing;~~

~~competition for production of electricity from non-coal sources, including the price and availability of alternative fuels;~~

~~domestic air emission standards for coal-fueled power plants and the ability of coal-fueled power plants to meet these standards by installing scrubbers~~we are not aware may exist now or ~~other means;~~

~~adverse weather, climate or other natural conditions, including natural disasters;~~

~~domestic and foreign taxes;~~

~~domestic and foreign economic conditions, including economic slowdowns;~~

~~the proximity to, capacity of and cost of transportation and port facilities;~~

~~market price fluctuations for sulfur dioxide emission allowances;~~

~~the level of capital expenditures it makes;~~

~~the cost of acquisitions;~~

~~its debt service requirements and other liabilities;~~

~~fluctuations in its working capital needs;~~

~~its ability to borrow funds and access the capital markets;~~

~~restrictions contained~~arise in the ~~debt agreements~~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 ~~which it is a party; and~~

discover in the ~~amount~~course of ~~cash reserves established by its general partner.~~

~~Any adverse change~~performing due diligence in connection with these ~~and other factors could result in a decline in WMLP’s ability~~acquisitions or for costs associated with known liabilities that exceed our estimates. Under the various purchase arrangements relating to ~~have sufficient cash to pay distributions and, in turn, would negatively affect our cash flow.~~

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

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

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~~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.~~

~~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.~~

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

~~the determination of the amount of cash to be distributed to WMLP’s limited partners and the amount of cash to be reserved for the future conduct of WMLP’s business; and~~

~~the determination whether to make borrowings under WMLP’s revolving credit facility to pay distributions to its limited partners.~~

In addition, subject to certain conditions, the Term Loan Credit Agreement, the Indenture and the Revolving Credit Facility Agreement 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 Term Loan or the 8.75% Notes or borrowers under the Revolving Credit Facility.

~~Because we own a controlling interest in WMLP, any internal control deficiencies at WMLP could impact our ability to accurately report our financial results or prevent fraud.~~

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;

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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

~~administrative~~ functions; and

identifying the potential unknown liabilities associated with ~~the Acquisitions.~~these acquisitions.

In addition, overall integration will require substantial attention from our management, particularly in light of the geographically dispersed operations of acquired mines relative to our other mines and operations and the unique characteristics of the acquired assets. If our senior management team is required to devote considerable amounts of time to the integration process, it will decrease the time they will have to manage our business, develop new strategies and grow our business. If our senior management is not able to manage the integration process effectively, or if any significant business activities are interrupted as a result of the integration process, our business could suffer.

Furthermore, the anticipated benefits and synergies of acquisitions are based on assumptions and current expectations, with limited actual experience, and assume that we will successfully integrate and reallocate resources without unanticipated costs and that our efforts will not have unforeseen or unintended consequences. In addition, our ability to realize the benefits and synergies of the acquisitions could be adversely impacted to the extent that relationships with existing or potential

customers, suppliers or the workforce is adversely affected as a consequence of ~~the Acquisitions,~~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’~~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

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

In addition, our management may be required to devote significant time and resources to adapting our systems, policies and procedures in order to successfully manage the integration and operation of foreign assets.

~~The Buckingham Acquisition may subject us to increased regulation and risks associated with underground mining.~~

The operations we acquired in the Buckingham acquisition primarily consist of underground mines. Underground mining operations are generally subject to more stringent safety and health standards than surface mining operations. More stringent state and federal mine safety laws and regulations have included increased sanctions for non-compliance. Future workplace accidents are likely to result in more stringent enforcement and possibly the passage of new laws and regulations. Our re-entry into underground mining operations will subject us to increased regulatory scrutiny and increased costs of regulatory compliance.


ITEM 1B	— UNRESOLVED STAFF COMMENTS.

~~None~~None.


ITEM 2	— PROPERTIES.

See ~~“Coal - U.S. Segment -~~ ~~Properties”, “Coal - Canada Segment -~~ ~~Properties”, “Coal - WMLP Segment -~~ ~~Properties”, and “Power Segment” under~~ 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"~~“Dodd-Frank Act”). Section 1503(a) of the Dodd-Frank Act contains reporting requirements regarding mine safety. Mine safety violations ~~and~~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 Disclosureto this ~~report~~Annual Report on Form 10-K.

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PART II


ITEM 5	— MARKET FOR REGISTRANT’S COMMON EQUITY, RELATED STOCKHOLDER MATTERS AND ISSUER PURCHASES OF EQUITY SECURITIES.

Market Information

Our common stock is listed and traded on the ~~NASDAQ~~Nasdaq Global Market under the symbol WLB.

Holders

As of March ~~3, 2015, based on inquiry~~29, 2018, there were ~~1,069~~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~~Nasdaq Global ~~Market.~~Market:


	Sales Prices Common Stock				Sales Prices Common Stock
	High		Low		High		Low
2013
2016
First Quarter	$	12.00	$	9.40	$	8.05	$	3.44
Second Quarter	12.30		10.77		10.03		6.15
Third Quarter	13.79		10.96		10.44		7.49
Fourth Quarter	19.75		12.91		19.92		8.26
2014

2017
First Quarter	$	30.00	$	18.31	$	19.03	$	11.58
Second Quarter	37.15		25.79		15.28		4.33
Third Quarter	45.19		33.60		4.93		1.88
Fourth Quarter	40.99		27.49		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 ~~Indenture,~~8.75% Notes, the Term Loan, ~~Credit Agreement~~San Juan Loan and the ~~Revolving Credit Facility Agreement~~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~~board of directors and will be subject to limitations imposed under Delaware law.

Securities Authorized for Issuance Under Equity Compensation Plans

The information relating to our equity compensation plans required by Item 5 is incorporated by reference to such information set forth in Item 12 - Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters contained herein.

Issuer ~~Purchase~~Purchases of Equity Securities

~~None.~~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

~~This~~The following performance graph compares the cumulative total stockholder return on our common stock for the five-year period December 31, ~~2009~~2012 through December 31, ~~2014~~2017 with (i) the cumulative total return over the same period of the ~~NASDAQ~~Nasdaq Financial Index, (ii) the cumulative total return over the same period of the ~~NYSE MKT Composite~~SPDR S&P Metals and Mining Index, and

(iii) our ~~former peer group,~~Peer Group Index, which ~~consisted~~consists of Alliance Resource Partners ~~L.P.,~~LP, Cloud Peak Energy, ~~Inc., James River Coal Company, Rhino Resource Partners, L.P.~~ and Patriot Coal Corporation and (iv) our current peer group index, which consists of Arch Coal Inc., Alliance Resource Partners, L.P., Cloud Peak Energy, Inc., Foresight Energy LP, Peabody Energy Corporation, and Rhino Resource Partners, L.P.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, ~~2009;~~2012;

All dividends were reinvested;

Annual ~~reweighting~~re-weighting of the peer ~~groups;~~group indices; and

You continued to hold your investment through December 31, ~~2014~~.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

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an opinion of management that such indices are necessarily an appropriate measure of the relative performance of our common stock.

At December 31,
Company/Market/Peer Group 2009 2010 2011 2012 2013 2014
Westmoreland Coal Company $ 100.00
$ 134.01
$ 143.10
$ 104.83
$ 216.50
$ 372.73
NYSE MKT Composite Index $ 100.00
$ 125.53
$ 133.39
$ 142.30
$ 151.25
$ 156.94
NASDAQ Financial Index $ 100.00
$ 113.56
$ 103.72
$ 124.50
$ 175.23
$ 188.39
2014 Peer Group Index $ 100.00
$ 147.57
$ 84.86
$ 65.55
$ 57.00
$ 35.67
2013 Peer Group Index $ 100.00
$ 142.88
$ 114.88
$ 83.14
$ 99.55
$ 94.26



	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

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ITEM 6	— SELECTED FINANCIAL DATA.

Westmoreland Coal Company and Subsidiaries

~~Five-Year Review~~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
	2014⁽²⁾			2013			2012⁽³⁾			2011			2010			(In thousands, except per share amounts)
Consolidated Statements of Operations Information	(In thousands; except per share data)
Revenues	$	1,115,992		$	674,686		$	600,437		$	501,713		$	506,057		$	1,384,568		$	1,477,960		$	1,419,518		$	1,131,000		$	686,055
Operating income (loss)	(42,975		)	25,362			28,872			10,626			20,521
Loss from continuing operations⁽¹⁾	(173,180		)	(8,127		)	(13,662		)	(36,875		)	(3,170		)
Less net loss attributable to noncontrolling interest	(921		)	(3,430		)	(6,436		)	(3,775		)	(2,645		)
Less preferred stock dividend requirements	859			1,360			1,360			1,360			1,360
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	$	(173,118	)	$	(6,057	)	$	(8,586	)	$	(34,460	)	$	(1,885	)	(3.82		)	(1.47		)	(11.93		)	(11.08		)	(0.64		)
Per common share (basic and diluted):
Loss from continuing operations	$	(10.86	)	$	(0.56	)	$	(0.97	)	$	(2.80	)	$	(0.29	)
Net loss applicable to common shareholders	$	(10.86	)	$	(0.42	)	$	(0.61	)	$	(2.61	)	$	(0.17	)
Consolidated Balance Sheet Information (end of period)
Working capital deficit	$	(13,126	)	$	(7,989	)	$	(11,600	)	$	(21,669	)	$	(35,793	)
Consolidated Balance Sheets Information (end of period)
Net property, plant and equipment	927,662			490,036			512,840			396,732			416,955			$	741,835		$	835,521		$	746,842		$	986,603		$	538,946
Total assets	1,829,578			946,685			936,115			759,172			750,306
Total debt	984,787			339,837			360,989			282,269			242,104
Shareholders’ deficit	(349,445		)	(187,879		)	(286,231		)	(249,858		)	(162,355		)
Other Consolidated Data:
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	$	50,353		$	80,717		$	57,144		$	44,735		$	45,353		$	114,163		$	151,934		$	45,562		$	50,353		$	80,717
Investing activities	(432,772		)	(21,897		)	(123,534		)	(33,639		)	(29,180		)	10,661			(155,694		)	(70,801		)	(432,772		)	(21,897		)
Financing activities	338,706			(29,320		)	67,217			13,912			(20,917		)	(82,802		)	40,122			36,723			338,706			(29,320		)
Capital expenditures	50,326			28,591			21,032			27,594			22,814			35,016			46,132			77,921			50,326			28,591
Adjusted EBITDA⁽⁴⁾	175,351			116,265			105,432			73,116			81,616			269,332			271,855			222,832			187,669			127,634
Tons sold	44,849			24,927			21,745			21,816			25,152			49,734			54,685			53,334			44,849			24,927

____________________


(1)	~~Includes a~~ 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 ~~on extinguishment~~ of ~~debt of $49.2~~$(1.9) million, ~~$0.1~~$(24.1) million, ~~$2.0~~$5.6 million and ~~$17.0 million in 2014, 2013, 2012 and 2011, respectively. Includes a derivative loss of~~ $31.1 million in ~~2014. Includes restructuring~~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. ~~Includes a non-cash tax benefit~~Restructuring charges in 2014 were incurred in connection with our acquisition of ~~$4.9 million in 2013.~~our Coal - Canada operating segment, as well as our acquisition of the general partner of WMLP.

(2)

~~On April 28, 2014, we acquired the Canadian Subsidiaries. Our results~~

Includes income tax benefit of ~~operations include the Canadian Subsidiaries’ results of operations~~$46.1 million in 2016 from the ~~date~~acquisition of ~~acquisition. On December 31,~~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 ~~we acquired Westmoreland Resources GP, LLC; therefore, balance sheet information~~ and ~~cash flow information includes the effect of this acquisition.~~2013, respectively.

(3)

OnDue to the adoption of ASU 2015-03 on January 1, 2016 and ASU 2015-17 on December 31, ~~2012, we acquired~~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 ~~Kemmerer Mine. Our results~~adoption of ~~operations include Kemmerer’s results~~ASU 2015-03, total debt for years shown are also presented net of ~~operations from the date of acquisition. Kemmerer’s results are reflected in our Coal - U.S. segment. We acquired additional~~ debt ~~to finance the acquisition of the Kemmerer Mine.~~discounts and unamortized debt issuance costs.


(4)	Adjusted EBITDA, a non-GAAP measure, is defined and reconciled to net loss at the end of ~~this “Selected~~Item 6 - Selected Financial ~~Data” section.~~Data.


(5)	On April 28, 2014, we completed the Canadian Acquisition. On December 31, 2014, we acquired WMLP. On January 31, 2016, we acquired the San Juan mine. Our results of operations, balance sheets, and other consolidated data include the acquired entities subsequent to their respective dates of acquisition.

~~We did not declare cash dividends on common shares for the five years ended December 31,~~ ~~2014~~. The financial data presented above should be read in conjunction with Item 7 - Management’s Discussion and Analysis of Financial Condition and Results of ~~Operation in Part II, Item 7~~Operations of this report, which includes a discussion of factors that materially affect the

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

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

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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 ~~reconciles~~reconcile Adjusted EBITDA to net loss, the most directly comparable GAAP financial measure.

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Reconciliation of Adjusted EBITDA to Net Loss																Years Ended December 31,
	For the Years Ended December 31,															2017			2016			2015			2014			2013
	2014			2013			2012			2011			2010			(In thousands)
	(In thousands)
Reconciliation of Adjusted EBITDA to Net loss

Net loss	$	(173,180	)	$	(8,127	)	$	(13,662	)	$	(36,875	)	$	(3,170	)	$	(73,135	)	$	(28,872	)	$	(219,095	)	$	(176,746	)	$	(11,274	)

Income tax (benefit) expense from continuing operations	232			(4,782		)	90			(426		)	(141		)
Income tax expense (benefit)																(5,890		)	(48,059		)	(19,890		)	23			(6,678		)
Interest income	(6,400		)	(1,366		)	(1,496		)	(1,444		)	(1,747		)	(4,101		)	(7,435		)	(7,993		)	(6,400		)	(1,366		)
Interest expense	84,234			39,937			42,677			29,769			22,992			118,657			121,819			101,311			82,320			39,937
Depreciation, depletion and amortization	100,778			67,231			57,145			45,594			44,690			121,054			185,267			140,328			109,361			74,430
Accretion of ARO and receivable	21,604			12,681			12,189			10,878			11,540
Amortization of intangible assets and liabilities	138			665			658			657			590
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	27,406			106,239			97,601			48,153			74,754			200,827			262,333			32,543			39,724			117,608

Advisory fees⁽²⁾																5,423			—			—			—			—
Restructuring charges	14,989			5,078			—			—			—			—			—			656			14,989			5,078
Loss on foreign exchange	4,016			—			—			—			—
Loss (gain) on foreign exchange																3,108			715			(3,674		)	4,016			—
Loss on impairment																5,872			—			136,210			—			—
Loss on extinguishment of debt	49,154			64			1,986			17,030			—			—			—			5,385			49,154			64
Acquisition related costs ⁽¹⁾	26,785			—			—			—			—
Customer payments received under loan and lease receivables⁽²⁾	12,388			—			—			—			—
Derivative loss	31,100			—			—			—			—
Loss (gain) on sale of assets and other adjustments	3,431			(438		)	(195		)	3,212			2,813
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	6,082			5,322			6,040			4,721			4,049			3,200			7,584			7,748			6,082			5,322
Adjusted EBITDA	$	175,351		$	116,265		$	105,432		$	73,116		$	81,616		$	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 onin 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 ~~Acquisition.~~mines.

~~(2)~~(4)

Represents a return of and on capital. These amounts are not included in operating income ~~or operating cash flows,~~(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.

~~Table of Contents~~


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~~Cautionary Note Regarding Forward-Looking ~~Statements”~~Statements and ~~“Risk Factors”~~Item 1A - Risk Factors.

This discussion should be read in conjunction with our consolidated financial statements and notes thereto contained in Item ~~1 above.~~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 ~~an energy company employing approximately 3,440 employees. We conduct our operations~~primarily on mine locations which allow us to employ dragline surface mining methods and take advantage of close customer proximity through ~~our subsidiaries~~mine-mouth power plants and ~~the principal sources of cash flow to us are distributions from our operating subsidiaries.~~strategically located rail transportation. Our coal operations include ~~13 wholly-owned~~surface coal mines in the ~~U.S.~~United States and Canada, underground coal mines in Ohio and New Mexico, a char production facility, and a 50% ~~stake~~interest in an activated carbon ~~plant, and two coal-fired power generation units.~~plant. We also own the general partner of, and ~~79%~~a majority of the ~~total~~ equity ~~interest~~interests in, ~~WMLP.~~

~~We classify our business into six segments: Coal - U.S., Coal - Canada, Coal -~~ WMLP, Power, Heritage and Corporate. Our principal operating segments are our Coal - U.S., Coal - Canada, Coal - WMLP and Power segments. Our two non-operating segments are our heritage and corporate segments. Our heritage segment primarily includes the costs of benefits we provide to former mining operation employees and our corporate segment consists primarily of corporate administrative expenses.

~~One of the major factors affecting the volume of~~a publicly traded coal that we sell in any given year is the demand for coal-generated electric power, as well as the specific demand for coal by our customers. Numerous factors affect the demand for electric power and the specific demands of customers including weather patterns, the presence of hydro or wind in our particular energy grids, environmental and legal challenges, political influences, energy policies, international and domestic economic conditions, power plant outages and other factors discussed herein.master limited partnership.

We sell almost all of our coal ~~and electricity production~~ under long-term agreements. Our long-term coal contracts typically contain either full pass-through of our costs or price escalation and adjustment provisions, pursuant to which the price for our coal may be periodically revised in line with broad economic indicators such as the consumer price index, commodity-specific indices such as the PPI-light fuel oils index, and/or changes in our actual costs. ~~We refer to these contracts as “cost protected” contracts.~~

For our contracts that are not cost protected in nature, we have exposure to inflation and price risk for supplies used in the normal course of production such as diesel fuel and explosives. ~~In line with the worldwide mining industry, we have experienced increased operating costs for mining equipment, diesel fuel and other supplies, such as tires.~~ We manage these items through strategic sourcing contracts in normal quantities with our suppliers and may use derivatives from time-to-time.

~~Please see~~ 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 ~~under “Overview,” “2014 Transactions,” “Recent Developments”~~- Overview and ~~“Power Segment”~~ Item 1 - Business - Segment Information for ~~information regarding the following transactions that occurred during 2014:~~a general description of our business and our business segments.

~~Canadian Acquisition~~

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.

~~Equity Offering~~

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).

~~Sale~~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 ~~Port Access~~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.

~~Debt Restructuring (including the tender offer, 8.75% Notes offering, Term Loan and Revolving Credit Facility)~~

~~WMLP Transactions~~

~~Buckingham Acquisition~~

~~ROVA Agreement~~

~~Table of Contents~~

Results of Operations

~~Items that Affect Comparability of Our Results~~

~~For~~ ~~2014~~ ~~and each of the prior two years, our results have included items that do not relate directly to ongoing operations. The income (expense) components of these items were as follows:~~

Year Ended December 31, 2014 2013 2012
(In thousands)
Loss on extinguishment of debt $ (49,154 ) $ (64 ) $ (1,986 )
Derivative loss (31,100 ) —
—
Acquisition and transition costs (26,785 ) —
—
Restructuring charges (14,989 ) (5,078 ) —
Incremental interest incurred before close of transaction (11,191 ) —
—
Canadian Acquisition bridge facility commitment fee (4,875 ) —
—
Foreign exchange loss (4,016 ) —
—
Impact (pre-tax) $ (142,110 ) $ (5,142 ) $ (1,986 )
Tax effect of other comprehensive income gains $ —
$ 4,892
$ —

~~Items recorded in 2014~~

We recorded $49.2 million of loss on extinguishment of debt related to the payoff of the 10.75% Notes, the WML term debt, and the WMLP debt. This loss included $44.5 million of make-whole payments with the remaining loss due to the write-off of unamortized debt issuance costs, debt discounts, and debt premiums.

~~We recorded $31.1 million of derivative losses related to ROVA's purchased-power contracts.~~

We recorded $26.8 million of acquisition and transition costs as a result of our WMLP and Canadian Acquisitions, which includes the impact on cost of sales related to the sale of inventory written up to fair value in the acquisition.

We recorded $15.0 million of restructuring charges related to a restructuring plan in order to reduce our overall cost structure. Most of the restructuring charges related to our Canadian and WMLP operations and included termination benefits and outplacement costs.

We recorded $11.2 million of incremental interest expense related to the $425 million of additional 10.75% Notes issued in connection with the Canadian Acquisition. This incremental interest represents interest expense from the February 7, 2014 closing date of the 10.75% Notes to the April 28, 2014 closing date of the Canadian Acquisition.

We recorded $4.9 million of interest expense related to the Canadian Acquisition bridge facility. Upon closing of the $425 million private offering of 10.75% Notes, our bridge facility commitment expired unexercised and as a result, the related commitment fee of $4.9 million was expensed and is included in ~~Interest expense.~~

We recorded a $4.0 million loss on foreign exchange. The majority of this loss relates to two foreign currency exchange forward contracts to purchase Canadian dollars in order to hedge a portion of our exposure to fluctuating rates of exchange on Canadian dollar-denominated Canadian Acquisition cash flows.

~~Items recorded in 2013~~

We recorded $0.1 million of loss on extinguishment of debt related to repurchases of 10.75% Notes with a principal amount of $0.5 million. The loss on the repurchases was measured based on the carrying value of the repurchased portion of the 10.75% Notes, which included a portion of the unamortized debt issue costs and the debt discount on the dates of repurchase.

~~We recorded $5.1 million of restructuring charges related to the ROVA restructuring.~~

~~We recorded an income tax benefit of $4.9 million related to a tax effect of other comprehensive income gains, primarily related to decreases in our pension and postretirement medical obligations.~~

~~Table of Contents~~

~~Items recorded in 2012~~

~~We recorded~~ ~~$2.0 million~~ of loss on extinguishment of debt related to repurchases of 10.75% Notes with a principal amount of $23.0 million. The loss on the repurchases was measured based on the carrying value of the repurchased portion of the 10.75% Notes, which included a portion of the unamortized debt issue costs and the debt discount on the dates of repurchase.

~~2014~~Year Ended December 31, 2017 Compared to ~~2013~~Year Ended December 31, 2016

~~Summary~~Consolidated Results of Operations

The following table shows the comparative consolidated results and changes between periods:


	Year Ended December 31,										Years Ended December 31,
							Increase / (Decrease)										Increase / (Decrease)
	2014			2013			$		%		2017			2016			$			%
	(In millions)										(In millions)
Revenues	$	1,116.0		$	674.7		$	441.3	65.4	%	$	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	(173.1		)	(6.1		)	167.0		2,737.7	%	(71.3		)	(27.1		)	(44.2		)	(163.1	)%
Adjusted EBITDA⁽¹⁾	175.4			116.3			59.1		50.8	%	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 ~~at the end of this “Results of Operations” section.~~in Item 6 - Selected Financial Data.

~~Our~~

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 ~~2014~~2017 increased ~~primarily due to~~$1.1 million compared with 2016. Offsetting the ~~Canadian Acquisition, new customer sales,~~revenue declines were lower costs resulting from fewer tons sold, higher margin reclamation work at Jewett, and ~~fewer customer outages.~~the non-recurrence of $66.8 million in charges and accelerated depreciation and depletion associated with the termination of production at the Jewett mine.

~~Our net~~

Net loss applicable to common shareholders ~~for 2014~~ 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 ~~$25.2~~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 ~~excluding $142.1~~early repayment of loan and lease receivables, representing an increase of $37.4 million ~~of expense during 2014~~over the prior year, as further described in "Recent Trends and ~~$0.2 million of expense during 2013 discussed in~~ ~~Items that Affect Comparability of Our Results. The primary factors, in aggregate, driving this increase in net loss were:~~Activities."

2014
(In millions)
Increase in interest expense due to increased debt levels $ (21.9 )
Decrease in our power segment operating income due to the renegotiated ROVA contract, unfavorable power prices and lower demand (13.4 )
Decrease in our Coal - U.S. segment primarily due to weather impacts as well as rail service issues at our Absaloka Mine (10.1 )
Increase in our Coal - Canada segment due to the Canadian Acquisition 19.3
Increase due to other factors 0.9
Total $ (25.2 )

Coal - U.S. Segment Operating Results

The following table shows the comparative ~~coal revenues, operating income~~results and ~~sales volume, and percentage~~ changes between ~~periods:~~periods for the Coal - U.S. segment:


	Year Ended December 31,									Years Ended December 31,
					Increase / (Decrease)										Increase / (Decrease)
	2014		2013		$			%		2017		2016			$			%
	(In thousands, expect per ton data)									(In millions)
Revenues	$	642,075	$	587,119	$	54,956		9.4	%	$	573.7	$	651.7		$	(78.0	)	(12.0	)%
Operating income	24,183		44,471		(20,288		)	(45.6	)%
Operating income (loss)										40.1		(8.1		)	48.2			*
Adjusted EBITDA⁽¹⁾	111,699		116,604		(4,905		)	(4.2	)%	129.3		126.6			2.7			2.1	%
Tons sold—millions of equivalent tons	28.3		24.9		3.4			13.7	%
Tons sold										20.0		24.1			(4.1		)	(17.0	)%

____________________


⁽¹⁾	Adjusted EBITDA, a non-GAAP measure, is defined and reconciled to net loss ~~at the end of this “Results of Operations” section.~~in Item 6 - Selected Financial Data.

~~Our 2014~~* Not meaningful.

Revenues for the Coal - U.S. ~~coal~~ segment ~~revenues and~~declined by 12.0% on 17.0% fewer coal tons sold ~~increased primarily due to new customer sales~~in 2017 as compared with 2016. This decline was driven by the expiration of coal supply agreements at ~~our Absaloka Mine and fewer customer outages affecting our Absaloka~~the Jewett and Beulah ~~Mines. Operating income was negatively impacted~~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

~~Table~~ higher revenue from San Juan resulting from strong performance at the mine and 12 months of ~~Contents~~

~~weather impacts, rail service issues~~ownership in 2017 compared with 11 months in 2016. Revenue from reclamation at ~~our Absaloka Mine, acquisition costs, and increased maintenance expenses. These decreases~~Jewett, which commenced in 2017, also offset the aforementioned revenue declines.

The segment generated $40.1 million in operating income ~~were partially~~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 ~~with increased revenues described above.~~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 ~~coal revenues, operating income~~results and ~~sales volume~~changes between ~~periods:~~periods for the Coal - Canada segment:


						Years Ended December 31,
	Year Ended December 31,									Increase / (Decrease)
	2014			2013		2017		2016		$			%
	(In thousands, expect per ton data)					(In millions)
Revenues	$	388,664		$	—	$	438.3	$	415.6	$	22.7		5.5	%
Operating income	(2,670		)	—		8.9		39.1		(30.2		)	(77.2	)%
Adjusted EBITDA⁽¹⁾	79,010			—		90.0		88.4		1.6			1.8	%
Tons sold—millions of equivalent tons	16.6			—
Tons sold						22.8		22.8		—			—	%

~~Table of Contents~~


ITEM 8	—FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA.



Index to Consolidated Financial Statements	Page

Report of Independent Registered Public Accounting Firm	7774

~~Report of Independent Registered Public Accounting Firm~~	78

Consolidated Balance Sheets	7975

Consolidated Statements of Operations	8176

Consolidated Statements of Comprehensive ~~Income (Loss)~~Loss	8277

Consolidated Statements of Shareholders’ Deficit	8378

Consolidated Statements of Cash Flows	8479

Notes to Consolidated Financial Statements	8680

~~Table of Contents~~

Report of Independent Registered Public Accounting Firm

~~The~~

To the Shareholders and the Board of Directors ~~and Shareholders~~ of Westmoreland Coal Company ~~and subsidiaries~~

Opinion on the Financial Statements

We have audited the accompanying consolidated balance sheets of Westmoreland Coal Company and subsidiaries (the ~~"Company"~~“Company”) as of December 31, ~~2014~~2017 and ~~2013, and~~2016, the related consolidated statements of operations, comprehensive ~~income (loss),~~loss, shareholders’ deficit, and cash flows for each of the three years in the period ended December 31, ~~2014. Our audits also included~~2017, and the related notes and financial statement schedule listed in the Index at Item ~~15.~~ 15 (collectively referred to as the “consolidated financial statements”). In our opinion, the consolidated financial statements present fairly, in all material respects, the financial position of the Company at December 31, 2017 and 2016, and the results of its operations and its cash flows for each of the three years in the period ended December 31, 2017, in conformity with U.S. generally accepted accounting principles.

We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States) (PCAOB), the Company's internal control over financial reporting as of December 31, 2017, based on criteria established in Internal Control-Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (2013 framework)and our report dated April 2, 2018 expressed an unqualified opinion thereon.

The Company's Ability to Continue as a Going Concern

The accompanying consolidated financial statements have been prepared assuming that the Company will continue as a going concern. As discussed in Note 1 to the financial statements, the Company has a substantial amount of long-term debt outstanding, is subject to declining industry conditions that are negatively impacting the Company’s financial position, results of operations, and cash flows, and has stated that substantial doubt exists about the Company’s ability to continue as a going concern. Management's evaluation of the events and conditions and management’s plans regarding these matters are also described in Note 1. The consolidated financial statements do not include any adjustments that might result from the outcome of this uncertainty.

Basis for Opinion

These financial statements ~~and schedule~~ are the responsibility of the Company's management. Our responsibility is to express an opinion on ~~these~~the Company’s financial statements based on our audits. We ~~did not audit~~are a public accounting firm registered with the ~~consolidated financial statements of Westmoreland Resources Partners, LP, a majority-owned subsidiary acquired on December 31, 2014, which reflects total assets constituting 17%~~Public Company Accounting Oversight Board (United States) (PCAOB) and are required to be independent with respect to the Company in accordance with the U.S. federal securities laws and the applicable rules and regulations of the ~~related consolidated total as of December 31, 2014~~Securities and ~~total revenue constituting 0% of~~Exchange Commission and the related consolidated total for the year then ended. Those statements were audited by other auditors whose report has been furnished to us, and our opinion, insofar as it relates to the amounts included for Westmoreland Resources Partners, LP, is based solely on the report of the other auditors.PCAOB.

We conducted our audits in accordance with the standards of the ~~Public Company Accounting Oversight Board (United States).~~PCAOB. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material ~~misstatement. An audit includes~~misstatement, whether due to error or fraud. Our audits included performing procedures to assess the risks of material misstatement of the financial statements, whether due to error or fraud, and performing procedures that respond to those risks. Such procedures included examining, on a test basis, evidence ~~supporting~~regarding the amounts and disclosures in the financial statements. ~~An audit~~Our audits also ~~includes assessing~~included evaluating the accounting principles used and significant estimates made by management, as well as evaluating the overall ~~financial statement presentation. We believe that our audits and the report~~presentation of ~~other auditors provide a reasonable basis for our opinion.~~

~~In our opinion, based on our audits and, as to the balance sheet at December 31, 2014, the report of other auditors~~ the financial statements referred to above present fairly, in all material respects, the consolidated financial position of Westmoreland Coal Company and subsidiaries at December 31, 2014 and 2013, and the consolidated results of their operations and their cash flows for each of the three years in the period ended December 31, 2014 ended in conformity with U.S. generally accepted accounting principles. Also, in our opinion, the related financial statement schedule, when considered in relation to the basic financial statements taken as a whole, presents fairly in all material respects the information set forth therein.

We have also audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), the Company's internal control over financial reporting as of December 31, 2014, based on the criteria established in ~~Internal Control-Integrated Framework~~ ~~issued by the Committee of Sponsoring Organizations of the Treadway Commission (2013 framework) and our report dated March 6, 2015 expressed an unqualified opinion thereon.~~

~~/s/ ERNST & YOUNG LLP~~

~~Denver, Colorado~~

~~March 6, 2015~~

~~Table of Contents~~

~~Report of Independent Registered Public Accounting Firm~~

~~Board of Directors and Unitholders of~~

~~Westmoreland Resource Partners, LP~~

We have audited the accompanying consolidated balance sheets of Westmoreland Resource Partners, LP (a Delaware limited partnership) and subsidiaries (the “Partnership”) as of December 31, 2014 (Successor) and Oxford Resource Partners, LP as of December 31, 2013 (Predecessor), and the related consolidated statements operations, partners’ capital (deficit) and cash flows for the period of December 31, 2014 (Successor) and the period from January 1, 2014 through December 31, 2014 and the two years in the period ended December 31, 2013 (Predecessor) (not presented herein). These financial statements are the responsibility of the Partnership’s management. Our responsibility is to express an opinion on these financial statements based on our audits.

We conducted our audits in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. We were not engaged to perform an audit of the Partnership’s internal control over financial reporting. Our audits included consideration of internal control over financial reporting as a basis for designing audit procedures that are appropriate in the circumstances, but not for the purpose of expressing an opinion on the effectiveness of the Partnership’s internal control over financial reporting. Accordingly, we express no such opinion. An audit also includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements, assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation.statements. We believe that our audits provide a reasonable basis for our opinion.

In our opinion, the consolidated financial statements referred to above present fairly, in all material respects, the financial position of Westmoreland Resource Partners, LP and subsidiaries as of December 31, 2014 (Successor) and December 31, 2013 (Predecessor), and the results of their operations and their cash flows for the period of December 31, 2014 (Successor) and the period from January 1, 2014 through December 31, 2014 and the two years in the period ended December 31, 2013 (Predecessor) in conformity with accounting principles generally accepted in the United States of America.

/s/ ~~GRANT THORNTON~~Ernst & Young LLP

~~Cleveland, Ohio~~

~~March 6, 2015~~We have served as the Company’s auditor since 2009.

Denver, Colorado

78April 2, 2018

~~Table of Contents~~

WESTMORELAND COAL COMPANY AND SUBSIDIARIES

Consolidated Balance Sheets


	December 31, 2014		December 31, 2013
	(In thousands)				December 31, 2017			December 31, 2016
Assets					(In thousands)
Current assets:
Cash and cash equivalents	$	14,258	$	61,110	$	103,247		$	60,082
Receivables:
Trade	143,052		66,196		103,611			140,731
Loan and lease receivables	10,493		—		—			5,867
Contractual third-party reclamation receivables	12,462		8,487
Other	19,923		5,086		17,697			13,261
	185,930		79,769
Total receivables					121,308			159,859
Inventories	133,855		39,972		106,795			125,515
Deferred income taxes	13,083		5,355
Restricted investments and bond collateral	—		5,998
Other current assets	13,645		12,835		11,517			32,258
Total current assets	360,771		205,039		342,867			377,714
Property, plant and equipment:
Land and mineral rights	500,226		278,188
Plant and equipment	956,112		657,696
	1,456,338		935,884
Land, mineral rights, property, plant and equipment					1,665,740			1,617,938
Less accumulated depreciation, depletion and amortization	528,676		445,848		923,905			782,417
Net property, plant and equipment	927,662		490,036
Loan and lease receivables	73,180		—
Net land, mineral rights, property, plant and equipment					741,835			835,521
Loan and lease receivables, less current portion					—			44,474
Advanced coal royalties	17,508		7,311		21,404			18,722
Reclamation deposits	77,907		74,921
Restricted investments and bond collateral	164,389		69,235
Contractual third-party reclamation receivables, less current portion	104,021		88,303
Restricted investments, reclamation deposits and bond collateral					200,194			219,275
Investment in joint venture	33,409		—		27,763			26,951
Intangible assets, net of accumulated amortization of $15.3 million and $14.1 million at December 31, 2014 and December 31, 2013, respectively	31,315		1,520
Other assets	39,416		10,320		55,036			62,252
Total Assets	$	1,829,578	$	946,685	$	1,389,099		$	1,584,909
Liabilities and Shareholders’ Deficit
Current liabilities:
Current installments of long-term debt					$	983,427		$	86,272
Accounts payable and accrued expenses:
Trade and other accrued liabilities					121,489			142,233
Interest payable					22,840			22,458
Production taxes					41,688			44,995
Postretirement medical benefits					14,734			14,892
Deferred revenue					5,068			15,253
Asset retirement obligations					48,429			32,207
Other current liabilities					9,401			20,964
Total current liabilities					1,247,076			379,274
Long-term debt, less current installments					64,980			1,022,794
Postretirement medical benefits, less current portion					317,407			308,709
Pension and SERP obligations, less current portion					43,585			43,982
Deferred revenue, less current portion					1,984			16,251
Asset retirement obligations, less current portion					426,038			451,834
Other liabilities					31,477			52,182
Total liabilities					2,132,547			2,275,026
Shareholders’ deficit:
Common stock of $0.01 par value: Authorized 30,000,000 shares; Issued and outstanding 18,771,643 shares at December 31, 2017 and 18,570,642 shares at December 31, 2016					188			186
Other paid-in capital					250,494			248,143
Accumulated other comprehensive loss					(160,525		)	(179,072		)
Accumulated deficit					(829,107		)	(757,367		)
Total shareholders’ deficit					(738,950		)	(688,110		)
Noncontrolling interests in consolidated subsidiaries					(4,498		)	(2,007		)
Total deficit					(743,448		)	(690,117		)
Total Liabilities and Shareholders' Deficit					$	1,389,099		$	1,584,909

See accompanying Notes to Consolidated Financial Statements.

~~Table of Contents~~

~~WESTMORELAND COAL COMPANY AND SUBSIDIARIES~~

~~Consolidated Balance Sheets (Continued)~~

December 31,
2014 December 31,
2013
(In thousands)
Liabilities and Shareholders’ Deficit
Current liabilities:
Current installments of long-term debt $ 43,136
$ 44,343
Revolving lines of credit 9,576
—
Accounts payable and accrued expenses:
Trade and other accrued liabilities 149,514
57,507
Interest payable 2,699
11,321
Production taxes 45,747
41,905
Workers’ compensation 671
717
Postretirement medical benefits 13,263
13,955
SERP 368
390
Deferred revenue 13,175
14,068
Asset retirement obligations 43,289
23,353
Other current liabilities 52,459
5,469
Total current liabilities 373,897
213,028
Long-term debt, less current installments 932,075
295,494
Workers’ compensation, less current portion 6,315
6,744
Excess of black lung benefit obligation over trust assets 11,252
8,675
Postretirement medical benefits, less current portion 293,156
270,374
Pension and SERP obligations, less current portion 49,779
24,176
Deferred revenue, less current portion 35,255
46,567
Asset retirement obligations, less current portion 409,456
256,511
Intangible liabilities, net of accumulated amortization of $13.5 million at December 31, 2014 and $12.4 million at December 31, 2013, respectively 4,538
5,606
Deferred income taxes 34,852
5,355
Other liabilities 28,448
2,034
Total liabilities 2,179,023
1,134,564
Shareholders’ deficit:
Preferred stock of $1.00 par value
Authorized 5,000,000 shares; Issued and outstanding 91,669 shares at December 31, 2014 and 159,960 shares at December 31, 2013, respectively 92
160
Common stock of $2.50 par value
Authorized 30,000,000 shares; Issued and outstanding 17,102,777 shares at December 31, 2014 and 14,592,231 shares at December 31, 2013, respectively 42,756
36,479
Other paid-in capital 185,644
134,861
Accumulated other comprehensive loss (124,296 ) (63,595 )
Accumulated deficit (468,902 ) (295,784 )
Total shareholders’ deficit (364,706 ) (187,879 )
Noncontrolling interests in consolidated subsidiaries 15,261
—
Total deficit (349,445 ) (187,879 )
Total Liabilities and Deficit $ 1,829,578
$ 946,685

~~See accompanying Notes to Consolidated Financial Statements.~~

~~Table of Contents~~

WESTMORELAND COAL COMPANY AND SUBSIDIARIES

Consolidated Statements of Operations


	Years Ended December 31,									Years Ended December 31,
	2014			2013			2012			2017			2016			2015
	(In thousands, except per share data)									(In thousands, except per share data)
Revenues	$	1,115,992		$	674,686		$	600,437		$	1,384,568		$	1,477,960		$	1,419,518
Cost, expenses and other:
Cost of sales	899,930			535,320			466,521
Cost of sales (exclusive of depreciation, depletion and amortization, shown separately)										1,096,098			1,156,687			1,175,849
Depreciation, depletion and amortization	100,778			67,231			57,145			121,054			185,267			140,328
Selling and administrative	100,528			50,721			49,908			120,184			108,560			95,554
Heritage health benefit expenses	13,388			13,418			13,388			12,633			11,777			14,573
Loss (gain) on sales of assets	1,232			(74		)	528
(Gain) loss on sale/disposal of assets										(2,671		)	(1,124		)	4,866
Loss on impairment										5,872			—			136,210
Restructuring charges	14,989			5,078			—			—			—			656
Derivative loss	31,100			—			—
Derivative (gain) loss										(1,929		)	(24,055		)	5,587
Income from equity affiliates	(3,159		)	—			—			(5,885		)	(5,591		)	(5,409		)
Other operating loss (income)	181			(22,370		)	(15,925		)	—			8,309			(3,000		)
	1,158,967			649,324			571,565			1,345,356			1,439,830			1,565,214
Operating income (loss)	(42,975		)	25,362			28,872			39,212			38,130			(145,696		)
Other income (expense):
Other (expense) income:
Interest expense	(84,234		)	(39,937		)	(42,677		)	(118,657		)	(121,819		)	(101,311		)
Loss on extinguishment of debt	(49,154		)	(64		)	(1,986		)	—			—			(5,385		)
Interest income	6,400			1,366			1,496			4,101			7,435			7,993
Loss on foreign exchange	(4,016		)	—			—
Other income	1,031			364			723
(Loss) gain on foreign exchange										(3,108		)	(715		)	3,674
Other (loss) income										(573		)	38			1,740
	(129,973		)	(38,271		)	(42,444		)	(118,237		)	(115,061		)	(93,289		)
Loss before income taxes	(172,948		)	(12,909		)	(13,572		)	(79,025		)	(76,931		)	(238,985		)
Income tax expense (benefit)	232			(4,782		)	90
Income tax benefit										(5,890		)	(48,059		)	(19,890		)
Net loss	(173,180		)	(8,127		)	(13,662		)	(73,135		)	(28,872		)	(219,095		)
Less net loss attributable to noncontrolling interest	(921		)	(3,430		)	(6,436		)	(1,795		)	(1,771		)	(5,453		)
Net loss attributable to the Parent company	(172,259		)	(4,697		)	(7,226		)	(71,340		)	(27,101		)	(213,642		)
Less preferred stock dividend requirements	859			1,360			1,360			—			—			3
Net loss applicable to common shareholders	$	(173,118	)	$	(6,057	)	$	(8,586	)	$	(71,340	)	$	(27,101	)	$	(213,645	)
Net loss per share applicable to common shareholders:
Basic and diluted	$	(10.86	)	$	(0.42	)	$	(0.61	)	$	(3.82	)	$	(1.47	)	$	(11.93	)
Weighted average number of common shares outstanding:
Basic and diluted	15,941			14,491			14,033			18,694			18,486			17,905

See accompanying Notes to Consolidated Financial Statements.

~~Table of Contents~~

WESTMORELAND COAL COMPANY AND SUBSIDIARIES

Consolidated Statements of Comprehensive ~~Income (Loss)~~Loss

Years Ended December 31,
2014 2013 2012
(In thousands)
Net loss $ (173,180 ) $ (8,127 ) $ (13,662 )
Other comprehensive income (loss)
Pension and other postretirement plans:
Amortization of accumulated actuarial gains or losses, pension 983
3,490
2,960
Adjustments to accumulated actuarial losses and transition obligations, pension (24,793 ) 28,974
(9,812 )
Amortization of accumulated actuarial gains or losses, transition obligations, and prior service costs, postretirement medical benefits 18
4,005
2,572
Adjustments to accumulated actuarial gains, postretirement medical benefits (19,442 ) 53,230
(22,342 )
Tax effect of other comprehensive income gains —
(4,892 ) —
Change in foreign currency translation adjustment (17,880 ) —
—
Unrealized and realized gains and losses on available-for-sale securities 413
(57 ) (268 )
Other comprehensive income (loss) (60,701 ) 84,750
(26,890 )
Comprehensive income (loss) attributable to Westmoreland Coal Company $ (233,881 ) $ 76,623
$ (40,552 )



	Years Ended December 31,
	2017			2016			2015
	(In thousands)
Net loss	$	(73,135	)	$	(28,872	)	$	(219,095	)
Other comprehensive income (loss)
Pension and other postretirement plans:
Amortization of accumulated actuarial gains and prior service costs, pension	2,826			4,361			1,886
Adjustments to accumulated actuarial gains and transition obligations, pension	3,376			3,010			160
Amortization of accumulated actuarial gains, transition obligations, and prior service costs, postretirement medical benefits	3,663			1,259			1,308
Adjustments to accumulated actuarial (losses) gains and transition obligations, postretirement medical benefits	(6,893		)	(22,066		)	7,322
Tax effect of other comprehensive income gains	(2,037		)	—			(3,335		)
Foreign currency translation adjustment gains (losses)	16,562			8,983			(51,866		)
Unrealized and realized gains (losses) on available-for-sale securities	1,065			(345		)	(1,738		)
Other comprehensive income (loss), net of income taxes	18,562			(4,798		)	(46,263		)
Comprehensive loss	(54,573		)	(33,670		)	(265,358		)
Less: Comprehensive loss attributable to noncontrolling interest	(1,780		)	(1,767		)	(5,453		)
Comprehensive loss attributable to common shareholders	$	(52,793	)	$	(31,903	)	$	(259,905	)

See accompanying Notes to Consolidated Financial Statements.

~~Table of Contents~~

WESTMORELAND COAL COMPANY AND SUBSIDIARIES

Consolidated Statements of Shareholders’ Deficit

Years Ended December 31, ~~2012~~, ~~2013~~2015, 2016 and ~~2014~~

2017

Preferred Stock Common Stock
Other
Paid-In
Capital

Accumulated
Other
Comprehensive Loss

Accumulated
Deficit

Non-controlling
Interest

Total
Shareholders’
Deficit
Shares Amount Shares Amount
(In thousands, except shares data)
Balance at December 31, 2011 159,960
$ 160
13,811,379
$ 34,527
$ 126,288
$ (121,455 ) $ (281,141 ) $ (8,237 ) $ (249,858 )
Preferred dividends declared —
—
—
—
—
—
(1,360 ) —
(1,360 )
Common stock issued as compensation —
—
323,432
808
5,232
—
—
—
6,040
Issuance of restricted stock —
—
66,600
167
(668 ) —
—
—
(501 )
Net loss —
—
—
—
—
—
(7,226 ) (6,436 ) (13,662 )
Other comprehensive loss —
—
—
—
—
(26,890 ) —
—
(26,890 )
Balance at December 31, 2012 159,960
160
14,201,411
35,502
130,852
(148,345 ) (289,727 ) (14,673 ) (286,231 )
Preferred dividends declared —
—
—
—
—
—
(1,360 ) —
(1,360 )
Common stock issued as compensation —
—
224,129
560
4,762
—
—
—
5,322
Assumption of noncontrolling interest of subsidiary —
—
—
—
—
—
—
18,103
18,103
Issuance of restricted stock —
—
166,691
417
(753 ) —
—
—
(336 )
Net loss —
—
—
—
—
—
(4,697 ) (3,430 ) (8,127 )
Other comprehensive income —
—
—
—
—
84,750
—
—
84,750
Balance at December 31, 2013 159,960
160
14,592,231
36,479
134,861
(63,595 ) (295,784 ) —
(187,879 )
Preferred dividends declared —
—
—
—
—
—
(859 ) —
(859 )
Common stock issued as compensation —
—
47,386
116
5,966
—
—
—
6,082
Common stock options exercised —
—
35,000
88
662
—
—
—
750
SARs exercised —
—
16,130
40
(40 ) —
—
—
—
Conversion of preferred stock (68,291 ) (68 ) 466,537
1,168
(1,100 ) —
—
—
—
Common stock issued to pension plan assets —
—
46,323
117
1,824
—
—
—
1,941
Offering shares —
—
1,684,507
4,211
52,262
—
—
—
56,473
Issuance of restricted stock —
—
214,663
537
(3,383 ) —
—
—
(2,846 )
Changes in WMLP ownership interest, net —
—
—
—
(5,408 ) —
—
5,408
—
Westmoreland Resource Partners, LP acquisition —
—
—
—
—
—
—
10,774
10,774
Net loss —
—
—
—
—
—
(172,259 ) (921 ) (173,180 )
Other comprehensive loss —
—
—
—
—
(60,701 ) —
—
(60,701 )
Balance at December 31, 2014 91,669
$ 92
17,102,777
$ 42,756
$ 185,644
$ (124,296 ) $ (468,902 ) $ 15,261
$ (349,445 )



	Preferred Stock					Common Stock				Other Paid-In Capital			Accumulated Other Comprehensive Loss			Accumulated Deficit			Non-controlling Interest			Total Shareholders’ Deficit
	Shares		Amount			Shares	Amount			Other Paid-In Capital			Accumulated Other Comprehensive Loss			Accumulated Deficit			Non-controlling Interest			Total Shareholders’ Deficit
	(In thousands, except shares data)
Balance at December 31, 2014	91,669		$	92		17,102,777	$	42,756		$	185,644		$	(128,007	)	$	(516,621	)	$	15,261		$	(400,875	)
Preferred dividends declared	—		—			—	—			—			—			(3		)	—			(3		)
WMLP distributions	—		—			—	—			—			—			—			(797		)	(797		)
Share-based compensation	—		—			269,567	100			7,648			—			—			—			7,748
Conversion of convertible notes and securities	(91,669	)	(92		)	604,557	1,511			(1,738		)	—			—			—			(319		)
Vesting of restricted stock less tax withholding	—		—			185,247	408			(3,705		)	—			—			—			(3,297		)
Changes in WMLP ownership percentage	—		—			—	—			8,279			—			—			(8,279		)	—
Change in par value of common stock from $2.50 to $0.01	—		—			—	(44,593		)	44,593			—			—			—			—
Net loss	—		—			—	—			—			—			(213,642		)	(5,453		)	(219,095		)
Other comprehensive loss	—		—			—	—			—			(46,263		)	—			—			(46,263		)
Balance at December 31, 2015	—		—			18,162,148	182			240,721			(174,270		)	(730,266		)	732			(662,901		)
WMLP distributions	—		—			—	—			—			—			—			(972		)	(972		)
Share-based compensation	—		—			342,353	3			7,581			—			—			—			7,584
Vesting of restricted stock less tax withholding	—		—			66,141	1			(159		)	—			—			—			(158		)
Net loss	—		—			—	—			—			—			(27,101		)	(1,771		)	(28,872		)
Other comprehensive loss	—		—			—	—			—			(4,802		)	—			4			(4,798		)
Balance at December 31, 2016	—		—			18,570,642	186			248,143			(179,072		)	(757,367		)	(2,007		)	(690,117		)
Cumulative effect of adoption of ASU 2016-16	—		—			—	—			—			—			(400		)	—			(400		)
WMLP distributions	—		—			—	—			—			—			—			(711		)	(711		)
Share-based compensation	—		—			—	—			3,200			—			—			—			3,200
Vesting of restricted stock less tax withholding	—		—			201,001	2			(849		)	—			—			—			(847		)
Net loss	—		—			—	—			—			—			(71,340		)	(1,795		)	(73,135		)
Other comprehensive income	—		—			—	—			—			18,547			—			15			18,562
Balance at December 31, 2017	—		$	—		18,771,643	$	188		$	250,494		$	(160,525	)	$	(829,107	)	$	(4,498	)	$	(743,448	)

See accompanying Notes to Consolidated Financial Statements.

~~Table of Contents~~

WESTMORELAND COAL COMPANY AND SUBSIDIARIES

Consolidated Statements of Cash Flows

Years Ended December 31,
2014 2013 2012
(In thousands)
Cash flows from operating activities:
Net loss $ (173,180 ) $ (8,127 ) $ (13,662 )
Adjustments to reconcile net loss to net cash provided by operating activities:
Depreciation, depletion and amortization 100,778
67,231
57,145
Accretion of asset retirement obligation and receivable 21,604
12,681
12,189
Non-cash tax benefits —
(4,892 ) —
Amortization of intangible assets and liabilities, net 138
665
658
Share-based compensation 6,082
5,322
6,040
Loss (gain) on sales of assets 1,232
(74 ) 528
Amortization of deferred financing costs 3,481
3,731
4,358
Other 1,087
(1,001 ) —
Loss on extinguishment of debt 49,154
64
1,986
Gain on sales of investment securities (241 ) (3 ) (165 )
Loss on derivative instruments 31,100
—
—
Loss on foreign exchange 4,016
—
—
Pension settlement/curtailment accounting 2,651
—
—
Income from equity affiliates (3,159 ) —
—
Distributions from equity affiliates 4,042
—
—
Changes in operating assets and liabilities:
Receivables (403 ) (7,636 ) (12,855 )
Inventories 45,335
(2,512 ) (2,164 )
Excess of black lung benefit obligation over trust assets 2,577
319
1,791
Deferred income tax (230 ) —
—
Accounts payable and accrued expenses (37,763 ) 13,579
17,399
Deferred revenue (12,246 ) (9,078 ) (8,198 )
Income tax payable 1,674
(1 ) —
Accrual for workers’ compensation (475 ) (2,069 ) (2,096 )
Asset retirement obligations (7,661 ) (9,410 ) (6,943 )
Accrual for postretirement medical benefits 2,665
7,721
6,191
Pension and SERP obligations (2,186 ) 2,388
2,802
Other assets and liabilities 10,281
11,819
(7,860 )
Net cash provided by operating activities 50,353
80,717
57,144
Cash flows from investing activities:
Additions to property, plant and equipment (50,326 ) (28,591 ) (21,032 )
Change in restricted investments and bond collateral and reclamation deposits (52,514 ) 1,434
(33,892 )
Cash payments in escrow for future acquisitions (34,000 ) —
—
Cash payments related to acquisitions (352,635 ) —
(72,522 )
Cash acquired related to acquisitions, net 8,173
—
—
Net proceeds from sales of assets 38,740
902
480
Proceeds from the sale of restricted investments 8,677
8,287
4,106

~~Table of Contents~~



	Years Ended December 31,
	2017			2016			2015
	(In thousands)
Cash flows from operating activities:
Net loss	$	(73,135	)	$	(28,872	)	$	(219,095	)
Adjustments to reconcile net loss to net cash provided by operating activities:
Depreciation, depletion and amortization	121,054			185,267			140,328
Accretion of asset retirement obligation	45,132			40,423			38,892
Share-based compensation	3,200			7,584			7,748
Non-cash interest expense	9,344			9,215			6,857
Amortization of deferred financing costs	10,778			11,537			10,601
Loss on extinguishment of debt	—			—			4,445
(Gain) loss on derivative instruments	(1,929		)	(24,055		)	5,587
Loss (gain) on foreign exchange	3,108			715			(3,674		)
Loss on impairment	5,872			—			136,210
Income from equity affiliates	(5,885		)	(5,591		)	(5,409		)
Distributions from equity affiliates	6,977			6,914			7,057
Deferred income taxes benefit	(5,909		)	(46,142		)	(17,961		)
Other	560			(2,705		)	(146		)
Changes in operating assets and liabilities:
Receivables	35,636			(4,430		)	1,987
Inventories	20,309			13,033			1,800
Accounts payable and accrued expenses	(20,180		)	10,505			(5,447		)
Interest payable	471			5,131			(5,569		)
Deferred revenue	(24,462		)	(7,370		)	(13,094		)
Other assets and liabilities	20,467			13,227			(19,613		)
Asset retirement obligations	(43,403		)	(32,452		)	(25,942		)
Return of derivative collateral	6,158			—			—
Net cash provided by operating activities	114,163			151,934			45,562
Cash flows from investing activities:
Additions to property, plant and equipment	(35,016		)	(46,132		)	(77,921		)
Proceeds from sales of restricted investments	50,226			34,814			15,532
Purchases of restricted investments	(54,281		)	(36,052		)	(28,670		)
Cash payments in escrow for future acquisitions	—			—			34,000
Cash payments related to acquisitions and other	(3,580		)	(120,992		)	(32,529		)
Cash acquired related to acquisition, net	—			—			2,780
Proceeds from sales of assets	4,990			7,695			2,224
Receipts from loan and lease receivables	50,488			8,987			21,954
Payments related to loan and lease receivables	—			(2,164		)	(5,654		)
Other	(2,166		)	(1,850		)	(2,517		)
Net cash provided by (used in) investing activities	10,661			(155,694		)	(70,801		)
Cash flows from financing activities:
Borrowings from long-term debt, net of debt discount	—			122,250			199,359
Repayments of long-term debt	(82,091		)	(70,370		)	(148,071		)
Borrowings on revolving lines of credit	275,300			423,500			201,746
Repayments on revolving lines of credit	(275,300		)	(425,500		)	(209,351		)
Debt issuance costs and other refinancing costs	—			(8,784		)	(8,132		)
Other	(711		)	(974		)	1,172
Net cash (used in) provided by financing activities	(82,802		)	40,122			36,723
Effect of exchange rate changes on cash	1,143			784			(2,806		)
Net increase in cash and cash equivalents	43,165			37,146			8,678
Cash and cash equivalents, beginning of year	60,082			22,936			14,258
Cash and cash equivalents, end of year	$	103,247		$	60,082		$	22,936
Supplemental disclosures of cash flow information:
Cash paid for interest	$	98,139		$	96,290		$	72,972
Cash paid for income taxes	—			1,316			434
Non-cash transactions:
Accrued purchases of property and equipment	$	4,019		$	6,496		$	3,766
Capital leases and other financing sources	1,333			27,355			15,232

Payments related to loan and lease receivables (5,682 ) —
—
Receipts from loan and lease receivables 8,039
—
—
Receivable from customer for property and equipment purchases 640
(389 ) (674 )
Other (1,884 ) (3,540 ) —
Net cash used in investing activities (432,772 ) (21,897 ) (123,534 )
Cash flows from financing activities:
Change in book overdrafts 141
310
(253 )
Borrowings from long-term debt, net of debt discount and premium 1,315,947
—
119,364
Repayments of long-term debt (955,177 ) (28,088 ) (44,846 )
Borrowings on revolving lines of credit 25,000
7,000
16,500
Repayments on revolving lines of credit (15,424 ) (7,000 ) (16,500 )
Debt issuance costs and other refinancing costs (88,144 ) (182 ) (5,688 )
Preferred dividends paid (859 ) (1,360 ) (1,360 )
Proceeds from issuance of common shares 56,473
—
—
Exercise of stock options 749
—
—
Net cash provided by (used in) financing activities 338,706
(29,320 ) 67,217
Effect of exchange rate changes on cash (3,139 ) —
—
Net increase (decrease) in cash and cash equivalents (46,852 ) 29,500
827
Cash and cash equivalents, beginning of year 61,110
31,610
30,783
Cash and cash equivalents, end of year $ 14,258
$ 61,110
$ 31,610
Supplemental disclosures of cash flow information:
Cash paid for interest $ 85,047
$ 36,252
$ 34,380
Cash paid (received) for income taxes 117
111
(73 )
Non-cash transactions:
Accrued purchases of property and equipment 11,740
1,112
634
Capital leases and other financing sources 15,599
5,371
1,828

See accompanying Notes to Consolidated Financial Statements.

~~Table of Contents~~

WESTMORELAND COAL COMPANY AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS


1.	~~SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES~~

1. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

Going Concern, Liquidity and Management’s Plan

The WMLP Term Loan matures on December 31, 2018 and WMLP does not currently have liquidity or access to additional capital sufficient to pay off this debt by its maturity date. This condition gives rise to substantial doubt about WMLP’s ability to continue as a going concern for one year after the issuance of their financial statements. Certain covenants in the WMLP Term Loan provide that an audit opinion on WMLP’s stand-alone consolidated financial statements that includes an explanatory paragraph referencing WMLP's conclusion that substantial doubt exists as to WMLP’s ability to continue as a going concern constitutes an event of default. The audit opinion in WMLP’s Annual Report on Form 10-K contains such an explanatory paragraph.

On March 1, 2018, the WMLP Term Loan lenders waived the event of default arising as a result of such explanatory paragraph being included in the audit opinion in WMLP’s Annual Report on Form 10-K. This waiver expires on the earlier occurrence of May 15, 2018 or upon the occurrence of any other event of default under the WMLP Term Loan. Unless WMLP obtains further waivers for or otherwise cures this event of default, the lenders could accelerate the maturity date of the WMLP Term Loan after the waiver expires, making it immediately due and payable. This event of default under the WMLP Term Loan would also constitute an event of default under our Term Loan and 8.75% Notes, making them also immediately due and payable. Accordingly, all outstanding principal balances and related debt issuance costs for the WMLP Term Loan, the Term Loan and the 8.75% Notes are presented as current debt in our consolidated financial statements. We do not currently have liquidity or access to additional capital sufficient to pay off this debt.

Our Revolver contains a financial covenant requiring that we maintain certain minimum fixed charge coverage ratios. On March 30, 2018, we executed an amendment to our Revolver with Canadian Imperial Bank of Commerce (formerly known as The PrivateBank and Trust Company), as agent and as lender, and East West Bank, as a lender, which amended, among other things, the calculation of Canadian EBITDA as it is used in the fixed charge coverage ratio. The amendment removed certain financial results attributable to the Coal Valley mine from Canadian EBITDA and results in our compliance with the covenant for the year ended December 31, 2017. Absent this amendment we would have failed to satisfy the financial covenant. The amendment also waives any covenant violation for the year ended December 31, 2017 that solely results from the receipt of an opinion from our independent registered public accounting firm that includes an explanatory paragraph referencing WCC’s conclusion that substantial doubt exists as to WCC’s ability to continue as a going concern.

Our San Juan Loan provides that the issuance of parent company (WCC) financial statements which include an audit opinion containing an explanatory paragraph referencing WCC's conclusion that substantial doubt exists as to WCC's ability to continue as a going concern constitutes an event of default thereunder. On March 28, 2018, we executed an extension and waiver agreement with NM Capital Utility Corporation, as lender, which, among other things, waived the requirement that the audit opinion included in our consolidated financial statements is without such an explanatory paragraph. This waiver expires on the earlier of May 1, 2019 or the occurrence of any event of default not already waived.

The impacts of declining industry conditions and significant debt service requirements on the Company’s financial position, results of operations, and cash flows gives rise to substantial doubt about our ability to pay our obligations as they come due. In consideration of the substantial amount of long-term debt outstanding and the aforementioned declining industry conditions and covenant defaults which required waivers or amendments to cure, the Company has engaged advisors to assist with the evaluation of strategic alternatives, which may include, but not be limited to, seeking a restructuring, amendment or refinancing of existing debt through a private restructuring or reorganization under Chapter 11 of the Bankruptcy Code. However, there can be no assurances that the Company will be able to successfully restructure its indebtedness, improve its financial position or complete any strategic transactions. As a result of these uncertainties and the likelihood of a restructuring or reorganization, management has concluded that there is substantial doubt regarding the Company’s ability to continue as a going concern.

The accompanying consolidated financial statements are prepared on a going concern basis and do not include any adjustments that might result from uncertainty about our ability to continue as a going concern, other than the reclassification of certain long-term debt and the related debt issuance costs to current liabilities and current assets, respectively. The report from the Company's independent registered public accounting firm on its consolidated financial statements included herein includes an explanatory paragraph that summarizes the salient facts or conditions that raise substantial doubt about the Company's ability to continue as a going concern.

Nature of Operations

Table of Contents

WESTMORELAND COAL COMPANY AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONT.)

Westmoreland Coal Company, or the ~~Company, Westmoreland, WCC,~~"Company," "Westmoreland," "WCC," "We," "Our" or the ~~Parent,~~"Parent," is an energy ~~company. The Company’s current~~mining company with our principal activities ~~are~~ conducted within the United States and Canada. Our U.S. ~~activities~~operations include the production and sale of coal from ~~its~~ mines in Montana, Wyoming, North Dakota, Texas, New Mexico and ~~Ohio and the ownership of the Roanoke Valley power plants, or ROVA, in North Carolina.~~Ohio. Our Canadian ~~activities~~operations include the production and sale of coal from six surface mines in Alberta and Saskatchewan, ~~selling~~a char production facility from which we sell char to the barbecue briquette industry, and a 50% ~~interest~~stake in an activated carbon ~~plant. The Company’s activities are primarily conducted through wholly owned subsidiaries.~~

U.S. Operations – The Company’s Kemmerer Mine is owned by its subsidiary Westmoreland Kemmerer, Inc., or Kemmerer. The Company’s Absaloka Mine is owned by its subsidiary Westmoreland Resources, Inc., or WRI. The Beulah, Jewett, Rosebud, and Savage Mines are owned through the Company’s subsidiary Westmoreland Mining LLC, or WML.

Canadian Operations – Prairie Mines & Royalty ULC ("PMRU") operates five surface coal mines in Alberta and Saskatchewan. PMRU owns and operates the Paintearth, Sheerness, Genesee, Poplar River and Estevan mines. PMRU directly owns a 50% joint venture interest in the Estevan Activated Carbon Joint Venture, at the Estevan mine,plant which produces activated carbon for the removal of mercury from flue gas. PMRU also sells char to the barbecue briquette industry. Coal Valley Resources Inc., "CVRI" operates the Coal Valley Mine which is a surface mine located in West Central Alberta where the majority of coal is exported overseas to Asian utility companies and commodity traders. CVRI operated the Obed Mountain surface mine, which ceased production in 2013 and is currently in reclamation.

Master Limited Partnership - On December 31, 2014, the Company acquired 100% of the outstanding units of Westmoreland Resources GP, LLC (formerly Oxford Resources GP, LLC) (the “GP”), the general partner of Westmoreland Resource Partners, LP (formerly Oxford Resource Partners, LP) (NYSE: WMLP, “WMLP”). Concurrent with the acquisition of the GP, Westmoreland contributed certain royalty-bearing coal reserves to WMLP in return for units issued by WMLP giving the Company an approximately 79% interest in WMLP. WMLP is a low-cost producer of high value steam coal in Northern Appalachia. WMLP markets its coal primarily to large electric utilities with coal-fire, base load scrubbed power plants under long-term coal sales contracts. See Note 2 for additional information.

Consolidation Policy

The Consolidated Financial Statements of Westmoreland Coal Company include the accounts of the Company and its controlled subsidiaries. The Company ~~consolidates any variable interest entity, or VIE, for which the Company is considered the primary beneficiary. The Company~~ provides for noncontrolling interests in consolidated subsidiaries in which the Company’s ownership is less than ~~100 percent~~100%. All intercompany accounts and transactions have been eliminated.

A VIE is an entity that is unable to make significant decisions about its activities or does not have the obligation to absorb losses or the right to receive returns generated by its operations. If the entity meets one of these characteristics, then the Company must determine if it is the primary beneficiary of the VIE. The party exposed to the majority of the risks and rewards with the VIE is the primary beneficiary and must consolidate the entity.

The Company has determined prior to December 31, 2013, it was the primary beneficiary in Absaloka Coal LLC, a VIE, in which it held less than a 50% ownership through December 31, 2013. The Company has consolidated this entity within the coal segment. The investment in Absaloka Coal LLC by its outside partner did not continue after December 31, 2013, and beginning in 2014, Absaloka Coal LLC is 100% owned by the Company, but ceased to have operations. As a result, the Company has unwound the transaction as of December 31, 2013 and concerning our balance sheet have decreased ~~Other liabilities~~ ~~by $19.1 million and decreased~~ ~~Noncontrolling interest~~ ~~by $18.1 million. As a result, as of December 31, 2013, the noncontrolling interest was eliminated.~~

The Company owns 100% of the GP equity units and thereby has controlling interest of WMLP. The Company includes the accounts of the GP and provides for a noncontrolling interest in WMLP, which was approximately 21% at December 31, 2014.

~~The Company's 50% interest in the Estevan Activated Carbon Joint Venture is accounted for under the equity method of accounting.~~ Investments in unconsolidated affiliates that the Company has the ability to exercise significant influence over, but not control, are accounted for under the equity method of accounting. Under the equity method of accounting, the Company records its proportionate share of the entity’s net income or loss at each reporting period in Income from equity affiliates onin the Consolidated Statements of Operations with a corresponding entry to increase or decrease the carrying value of the investment. The Company’s 50% interest in the Estevan Activated Carbon Joint Venture is accounted for under the equity method of accounting.

~~Table of Contents~~

~~WESTMORELAND COAL COMPANY AND SUBSIDIARIES~~

~~NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONT.)~~

Use of Estimates

The preparation of financial statements in conformity with ~~generally accepted accounting principles~~Generally Accepted Accounting Principles (“GAAP”) requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosures of contingent assets and liabilities at the date of the financial statements and reported amounts of revenues and expenses during the reporting period. Actual results could differ from those estimates.

Cash and Cash Equivalents

Cash and cash equivalents are stated at cost, which approximate fair value. Cash equivalents consist of highly liquid investments with original maturities of three months or less.

Trade Receivables

Trade receivables are recorded at the invoiced amount and do not bear interest. The Company evaluates the need for an allowance for doubtful accounts based on a review of collectability. The Company has determined that no allowance is necessary for trade receivables as of December 31, ~~2014~~ ~~and~~ ~~2013~~.2017 or 2016.

Loan and Lease Receivables

All loan and lease receivables were collected during the year ended December 31, 2017 and we do not expect to enter into any such transactions going forward. The Company ~~periodically executes~~historically executed loans and finance leases at the Genesee ~~Mine~~mine with its only customer for purposes of funding capital expenditures and working capital requirements. Finance lease and loan receivables ~~are~~were measured at ~~the present~~their carrying value ~~of the future lease payments~~ at the inception of the arrangement. Lease payments received ~~are~~were comprised of a repayment of principal and finance income. Finance income iswas recognized based on the interest rate implicit in the finance ~~lease. PMRU recognizes~~lease and recognized in Interest income on the Consolidated Statements of Operations. We recognized finance income over periods between three and twenty-seven years, , which ~~reflect~~reflected a constant periodic return on ~~its~~our net investment in the finance lease. ~~Initial direct costs are included in the initial measurement of the finance lease receivables and reduce the amount of income recognized over the lease term.~~

Inventories

Inventories ~~which~~ include materials and supplies, ~~as well as raw~~which are carried at historical cost less an obsolescence reserve, when necessary, and coal, ~~are stated~~which is carried at the lower of cost or ~~market.~~net realizable value. Cost of coal is determined using the average cost ~~method. Coal inventory costs include~~method and includes labor, supplies, equipment, depreciation, depletion, amortization, operating overhead and other related costs.

Exploration and Mine Development

Exploration expenditures are charged to Cost of sales as incurred, including costs related to drilling and study costs incurred to convert or upgrade mineral resources to reserves.

Table of Contents

WESTMORELAND COAL COMPANY AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONT.)

At existing surface operations, additional pits may be added to increase production capacity in order to meet customer requirements. These expansions may require significant capital to purchase additional equipment, relocate equipment, build or improve existing haul roads and create the initial pre-production box cut to remove overburden for new pits at existing operations. If these pits operate in a separate and distinct area of the mine, the costs associated with initially uncovering coal for production are capitalized and amortized over the life of the developed pit consistent with coal industry practices. Once production has begun, mining costs are then expensed as incurred.

Where new pits are routinely developed as part of a contiguous mining sequence, the Company expenses such costs as incurred. The development of a contiguous pit typically reflects the planned progression of an existing pit, thus maintaining production levels from the same mining area utilizing the same employee group and equipment.

Land, Mineral Rights, Property, Plant and Equipment

~~Property,~~Land, mineral rights, property, plant and equipment are recorded at ~~cost and includes long-term spare parts inventory.~~acquisition cost. Expenditures that extend the useful lives of existing plant and equipment, or increase productivity of ~~the assets~~plant and equipment, are capitalized. Maintenance and repair costs that do not extend the useful ~~life~~lives or increase productivity of ~~the asset~~plant and equipment are expensed as incurred. ~~Coal reserves are recorded at cost, or at fair value originally in the case of acquired businesses.~~

Coal reserves, mineral rights and mine development costs are depleted based upon estimated ~~recoverable~~ proven and probable reserves. Long-term spare parts inventory begins depreciation when placed in service. Plant and equipment are depreciated on a straight-line basis over the assets’ estimated useful lives as follows:

~~Table of Contents~~

~~WESTMORELAND COAL COMPANY AND SUBSIDIARIES~~

~~NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONT.)~~



	Years
Buildings and improvements	5 to 40
Machinery and equipment	31 to 36

~~Long-term spare parts inventory begins depreciation when placed in service.~~

The Company assesses the carrying value of its property, plant and equipment for impairment whenever events or changes in circumstances indicate that the carrying amount of an asset may not be recoverable. Recoverability is measured by comparing estimated undiscounted cash flows expected to be generated from such assets to their net book value. If net book value exceeds estimated cash flows, the asset is written down to fair value. When an asset is retired or sold, its cost and related accumulated depreciation and depletion are removed from the accounts. The difference between the net book value of the asset and proceeds on disposition is recorded as a gain or loss. Fully depreciated plant and equipment still in use is not eliminated from the accounts. Amortization of capital leases is included in Depreciation, depletion and amortization.

~~Other Current Receivables~~Deferred Longwall Costs

The Company defers the direct costs associated with longwall moves, including longwall set-up costs, supplies and ~~Other Current Liabilities~~refurbishment costs of longwall equipment at our San Juan mine. These deferred costs are expensed on a units-of-production basis into cost of coal produced (excluding depreciation, depletion and amortization) over the panel benefited by these costs, which has historically approximated one year.

~~Upon acquisition~~Impairment of ~~CVRI~~Long-Lived Assets

The Company evaluates its long-lived assets held and used in ~~2014,~~operations for impairment as events and changes in circumstances indicate that the carrying amount of such assets might not be recoverable. Factors that would indicate potential impairment to be present include, but are not limited to, a sustained history of operating or cash flow losses, an unfavorable change in earnings and cash flow outlook, prolonged adverse industry or economic trends or a significant adverse change in the extent or manner in which a long-lived asset is being used or in its physical condition.

Assets are grouped at the lowest level for which there are identifiable cash flows that are largely independent of the cash flows of other groups of assets. Coal mining assets are generally grouped at the mine level.

When indicators of impairment are present, the Company ~~became responsible~~evaluates its long-lived assets for remediation work for a breach on a containment pond at a currently inactive mine that occurred on October 31, 2013. The prior owner, Sherritt International Corporation, has indemnified Westmoreland against past and future liability stemming from the incident. As of December 31, 2014, the Company has recorded $16.2 million in ~~Other current liabilities~~ ~~for~~recoverability by comparing the estimated ~~costs~~undiscounted cash flows expected to be generated by those assets under various assumptions to their carrying amounts. If such undiscounted cash flows indicate that the carrying value of ~~remediation work~~the asset group is not recoverable, impairment losses are measured by comparing the estimated fair value of the asset group to its carrying amount. Fair value is generally determined through the use of an expected present value technique based on the income approach. The estimated future cash flows and ~~a corresponding amount~~underlying assumptions used to assess recoverability and, if necessary, measure the fair value of the Company’s long-lived asset groups are derived from those developed in ~~Other current receivables~~ ~~to reflect~~connection with the ~~indemnification by the prior owner~~Company’s planning and budgeting process.

Table of ~~CVRI.~~Contents

WESTMORELAND COAL COMPANY AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONT.)

Reclamation Deposits ~~and Contractual Third-Party Reclamation Receivables~~

Certain of the Company’s customers have ~~either agreed to reimburse the Company for reclamation expenditures as they are incurred or have~~ pre-funded a portion of ~~the~~ expected reclamation costs. Amounts received from customers and held on deposit are recorded aswithin Restricted investments, reclamation ~~deposits. Amounts that are reimbursable by customers are recorded as third-party reclamation receivables when the related reclamation obligation is recorded.~~deposits and bond collateral.

Financial Instruments

The Company evaluates all of its financial instruments to determine if such instruments are derivatives, derivatives that qualify for the normal purchase normal sale exception or instruments that contain features that qualify them as embedded derivatives. Except for derivatives that qualify for the normal purchase normal sale exception, all derivative financial instruments are recognized in the balance sheet at fair value. Changes in fair value are recognized in earnings if they are not eligible for hedge accounting or Accumulated other comprehensive ~~income (loss)~~loss if they qualify for ~~cash flow~~ hedge accounting.

Held-to-maturity financial instruments consist of non-derivative financial assets with fixed or determinable payments and a fixed term, which the Company has the ability and intent to hold until maturity, and, therefore, accounts for them as held-to-maturity securities. Held-to-maturity securities are recorded at amortized cost, adjusted for the amortization or accretion of premiums or discounts calculated on the effective interest method. Interest income is recognized when earned.

The Company has securities classified as available-for-sale, which are recorded at fair value. The changes in fair values are recorded as unrealized gains (losses) as a component of Accumulated other comprehensive ~~income (loss)~~loss in ~~shareholders’ deficit.~~the Consolidated Balance Sheets.

The Company reviews its securities routinely for other-than-temporary impairment. The primary factors used to determine if an impairment charge must be recorded because a decline in value of the security is other than temporary include (i) whether the fair value of the investment is significantly below its cost basis, (ii) the financial condition of the issuer of the security, (iii) the length of time that the cost of the security has exceeded its fair value and (iv) the Company’s intent and ability to retain the investment for a period of time sufficient to allow for any anticipated recovery in market value. Other-than-temporary impairments are recorded as a component of Other (loss) income ~~(expense)~~.

Fair Value

~~Fair~~ The fair value hierarchy prioritizes the inputs to valuation techniques used to measure fair ~~value~~value. The hierarchy, as defined below, gives the highest priority to unadjusted quoted prices in active markets for identical assets or liabilities and ~~is defined as:~~

~~Table of Contents~~the lowest priority to unobservable inputs.

~~WESTMORELAND COAL COMPANY AND SUBSIDIARIES~~

~~NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONT.)~~

Level 1, defined as observable inputs such as quoted prices in active markets for identical assets. Level 1 assets include available-for-sale equity securities generally valued based on independent third-party market prices.

Level 2, defined as observable inputs other than Level 1 prices. These include quoted prices for similar assets or liabilities in an active market, quoted prices for identical assets and liabilities in markets that are not active, or other inputs that are observable or can be corroborated by observable market data for substantially the full term of the assets or liabilities.

Level 3, defined as unobservable inputs in which little or no market data exists, therefore requiring an entity to develop its own assumptions.

~~The Company’s non-recurring fair value measurements include asset retirement obligations~~See Note 4 - Loss On Impairment, Note 6 - Restricted Investments, Reclamation Deposits And Bond Collateral and Note 13 - Fair Value Measurements to the ~~purchase price allocations for the fair value of assets and liabilities acquired through business combinations.~~

The Company determines the estimated fair value of its asset retirement obligations by calculating the present value of estimated cash flows related to reclamation liabilities using level 3 inputs. The significant inputs used to calculate such liabilities includes estimates of costs to be incurred, the Company’s credit adjusted discount rate, inflation rates and estimated dates of reclamation. The asset retirement liability is accreted to its present value each period and the associated mineral rights are depleted using the units-of-production method.

The fair value of assets and liabilities acquired through business combinations is calculated using a discounted-cash flow approach using level 3 inputs. Cash flow estimates require forecasts and assumptions for many years into the future for a variety of factors.

~~See Notes 4, 7, 8, 10, 11 and 12~~consolidated financial statements for further disclosures related to the ~~Company’s~~Company's fair value estimates.

Intangible Assets and Liabilities

Identifiable intangible assets or liabilities acquired in a business combination ~~must be~~are specifically identified and recognized ~~and reported separately from goodwill. Intangible assets result from more favorable market prices than contracted prices as measured during~~on a ~~business combination. Intangible liabilities result from less favorable market prices than contracted prices as measured during a business combination. Substantially all of these~~standalone basis. These intangible assets and liabilities are amortized on a straight-line basis over the respective ~~period~~useful life of the ~~agreements.~~

~~Amortization of intangible assets recognized in~~asset or liability. See ~~Cost of sales~~Note 7 - Intangible Assets And Liabilities ~~was $1.2 million in~~ ~~2014 and $1.7 million in 2013, and 2012. Amortization of intangible liabilities recognized in~~ ~~Revenues~~ ~~was $1.0 million in 2014, 2013, and 2012.~~

~~The estimated aggregate amortization amounts from intangibles assets and liabilities~~to the consolidated financial statements for ~~each of the next five years as of December 31, 2014 are as follows:~~

Amortization
Expense
(In thousands)
2015 $ 1,073
2016 1,073
2017 1,073
2018 1,073
2019 1,820
further details.

Workers’ Compensation Benefits

The Company is self-insured for workers’ compensation claims incurred prior to 1996. The liabilities for workers’ compensation claims are actuarially determined estimates of the ultimate losses incurred based on the Company’s experience. Adjustments to the ~~probable ultimate liabilities~~actuarially determined liability are made annually based on subsequent developments and experience and are included in operations at the time of the revised estimate.

The Company insures its current employees through third-party insurance providers and state arrangements.

8983

Table of Contents

WESTMORELAND COAL COMPANY AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONT.)

Pneumoconiosis (Black Lung) Benefits

The Company is self-insured for federal and state black lung benefits for former ~~heritage employees and has established an independent trust to pay these benefits.~~Heritage employees. The Company accounts for these benefits on the accrual basis. An independent actuary annually calculates the present value of the accumulated black lung obligation. The ~~underfunded status~~liability is included in ~~2014~~Other liabilities ~~and~~ ~~2013~~ ofon the ~~Company’s obligation is included as~~ ~~Excess of black lung benefit obligation over trust assets~~ ~~in the accompanying consolidated balance sheets. Actuarial gains and losses are recognized in the period in which they arise.~~Consolidated Balance Sheets.

The Company insures its current represented employees through arrangements with its unions and its current non-represented employees are insured through third-party insurance providers. The Company maintains actuarially determined accruals to account for estimates of the ultimate losses incurred.

Postretirement Health Care Benefits

The Company accrues the cost to provide the benefits over the employees’ period of active service for postretirement benefits other than pensions. These costs are determined on an actuarial basis. The Company’s ~~consolidated balance sheet reflects~~Consolidated Balance Sheets reflect the unfunded status of postretirement benefit obligations.

Pension and SERP Plans

The Company accrues the cost to provide the benefits over the employees’ period of active service for the non-contributory defined benefit pension and SERP plans it sponsors. These costs are determined on an actuarial basis. The Company’s ~~consolidated balance sheet reflects~~Consolidated Balance Sheets reflect the unfunded status of the defined benefit pension and SERP ~~plans.~~plans, with the current portion of the liability in Other current liabilities.

Deferred Revenue

Deferred revenues represent funding received ~~upon~~in advance of meeting the ~~negotiation of long-term contracts. The deferred~~revenue recognition criteria. Deferred revenues ~~for coal~~ will be recognized as ~~deliveries of~~revenue in the ~~reserved coal are made~~periods in accordance with the long-term coal contracts. Deferred power revenues are recognized on a pro rata basis, based on the payments estimated to be received over the remaining term of the power sales agreements.which all revenue recognition criteria have been met.

Asset Retirement Obligations

The Company’s asset retirement obligation, or ~~ARO, liabilities~~"ARO," primarily consist of estimated costs to reclaim surface land and support facilities at its mines and power plants in accordance with federal and state reclamation laws as established by each mining permit.

The Company estimates its ARO ~~liabilities~~ for final reclamation and mine closure based upon detailed engineering calculations of the amount and timing of the future costs for a third party to perform the required work. These estimates are based on projected pit configurations ~~at the end of mining~~ and are escalated for inflation, and then discounted at a credit-adjusted risk-free rate. The Company records ~~mineral rights~~asset retirement cost associated with the initial recorded liability. ~~Mineral rights are~~Asset retirement cost is amortized based on the units of production method over the estimated ~~recoverable,~~ proven and probable reserves at the related mine, and the ARO ~~liability~~ is accreted to the projected settlement date. Changes in estimates could occur due to revisions of mine plans, changes in estimated costs ~~and~~or changes in timing of the performance of reclamation activities.

Income Taxes

The Company is subject to income taxes in the U.S. (including federal and state) and certain foreign jurisdictions. Deferred income taxes are provided for temporary differences arising from differences between the financial statement amount and tax basis of assets and liabilities existing at each balance sheet date using enacted tax rates anticipated to be in effect when the related taxes are expected to be paid or recovered. A valuation allowance is established if it is more likely than not (greater than 50%) that a deferred tax asset will not be realized. In determining the need for a valuation allowance at each reporting period, the Company considers projected realization of tax benefits based on expected levels of future taxable income, the duration of statutory carryforward periods, experience with operating loss and tax credit carryforwards not expiring and availability of tax planning strategies.

Accounting guidance prescribes a recognition threshold and measurement attribute for the financial statement recognition and measurement of a tax position taken or expected to be taken in a tax return. Under this guidance, a company can recognize the benefit of an income tax position only if it is more likely than not (greater than 50%) that the tax position will be sustained upon tax examination, based solely on the technical merits of the tax position. Guidance is also provided on ~~the~~ derecognition, classification, interest and penalties, accounting in interim periods, disclosure and transition.

The Company includes interest and penalties related to income tax matters in income tax expense. Deferred tax liabilities and assets are classified as noncurrent in the Consolidated Balance Sheets.

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The tax effect of pretax income or loss from continuing operations is generally determined by a computation that does not consider the tax effects of items that are not included in continuing operations. The exception to that incremental approach is that all items (for example, items recorded in other comprehensive ~~income, extraordinary items, and discontinued operations)~~income) be considered in determining the amount of tax benefit that results from a loss from continuing operations and that shall be allocated to continuing operations.

Deferred Financing Costs

The Company capitalizes costs incurred in connection with ~~borrowings or~~ establishment of credit facilities and issuance of debt securities. These costs are amortized as an adjustment to interest expense over the life of the ~~borrowing~~debt security or term of the credit facility using the effective interest method. These amounts are recorded in the Consolidated Balance Sheets in Other assets in the ~~accompanying consolidated balance sheets.~~case of credit facilities and in the case of debt securities in Long-term debt, less current installments as a direct deduction of the carrying amount of the debt security, consistent with debt discounts in the Consolidated Balance Sheets.

Revenue Recognition

Revenue is recognized when the following criteria have been met: persuasive evidence of an arrangement exists, delivery has occurred, the fee is fixed or determinable and the collection of funds is reasonably assured.

Coal Revenues

The Company generally recognizes revenue from the sale of coal ~~sales revenue~~ at the time title passes to the customer in accordance with the terms of the underlying sales agreement. The point that title passes varies by agreement. Under our sales agreements, title transfer points include upon loading to truck or rail, upon delivery by truck or rail, upon loading to conveyor belt, upon delivery from conveyor belt and ~~after any contingent performance obligations have been satisfied.~~upon delivery to stockpile. Coal ~~sales~~ revenue is recognized based on the pricing contained in the contracts in place at the time that title passes. Certain of our coal contracts require that the customer reimburse us for reclamation expenditures when incurred. On the delivery of coal these reimbursements are generally not yet fixed or determinable. Accordingly, these reimbursements are not recognized as revenue until they become fixed or determinable, which generally occurs when reclamation expenditures are incurred. Reclamation expenditures may be incurred and the associated revenue related to reimbursements may be recognized during periods of coal delivery, or in some instances, may continue to be incurred and recognized for several years after coal deliveries have been completed.

Power Revenues

ROVA ~~supplies~~supplied power it ~~produces~~produced and ~~generates~~generated revenues from such ~~sales,~~deliveries, as well as through the settlement of related purchased power arrangements. ROVA may supply its customer substitute power not produced by ROVA during periods when it is uneconomical to operate the ROVA units. While the Company expects to continue to operate ROVA during high demand periods, the Company expects the facility to remain idle during low demand periods, during which it will meet the customer's power needs by purchasing power from a third party provider at a fixed price. Alternatively, the Company has the option to operate the ROVA units, sell its produced power to its customer and resell the purchased power into the open market.

A portion of the payment under the power sales agreement iswas considered to be an operating lease. The Company ~~is recognizing these~~recognized amounts previously invoiced as revenue on a ~~pro rata~~straight-line basis over the remaining term of the power sales agreement. ~~Under this method of recognizing revenue, $9.6 million and~~ ~~$8.7 million~~ ~~of previously deferred revenue was recognized during~~ ~~2014~~ ~~and~~ ~~2013, respectively.~~

Other Operating ~~Income (Loss)~~Loss (Income)

Other operating ~~income~~loss (income) in the ~~accompanying~~ Consolidated ~~Results~~Statements of Operations reflects items of income or loss from sources other than coal or power revenues. ~~Income from the Company’s Indian Coal Tax Credit monetization transaction is recorded as~~ ~~Other operating income~~. The Company recognizes other operating income aswhen business interruption losses ~~are~~have been incurred and reimbursement is ~~virtually assured and has recognized $16.2 million and $17.3 million of income during 2013 and 2012, respectively; which is included in~~ realized or realizable~~Other operating income.~~. Insurance proceeds are included in Net cash provided by operating activities. when received.

Share-Based Compensation

Share-based compensation expense is generally measured at the grant date and recognized as expense over the vesting period of the entire ~~award.~~award for stock-settled grants and remeasured at fair value at the end of each period and accrued as a liability for cash-settled grants. These costs are recorded in ~~Cost of sales~~ ~~and~~ Selling and administrative ~~expenses~~ in the ~~accompanying consolidated results~~Consolidated Statements of ~~operations.~~

~~Earnings (Loss) per Share~~

Basic earnings (loss) per share have been computed by dividing the net income (loss) applicable to common shareholders by the weighted average number of shares of common stock outstanding during each period. Net income (loss) applicable to common shareholders includes the adjustment for net income or loss attributable to noncontrolling interest. Diluted earnings (loss) per share is computed by including the dilutive effect of common stock that would be issued assuming conversion or exercise of outstanding convertible notes, stock options, stock appreciation rights, restricted stock and warrants. No such items were included in the computation of diluted loss per share for the years endedOperations. See ~~2014~~Note 14 - Share-Based Compensation , ~~2013~~ or ~~2012~~ ~~because the Company incurred a loss from operations in each of these periods and the effect of inclusion would have been anti-dilutive.~~

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~~WESTMORELAND COAL COMPANY AND SUBSIDIARIES~~

~~NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONT.)~~

~~The table below shows the number of shares that were excluded from the calculation of diluted loss per share because their inclusion would be anti-dilutive~~ to the ~~calculation:~~

Years Ended December 31,
2014 2013 2012
(In thousands)
Convertible notes and securities 626
1,093
1,093
Restricted stock units, stock options, and SARs 537
805
978
Total shares excluded from diluted shares calculation 1,163
1,898
2,071
consolidated financial statements for further details.

Derivatives

The Company enters into financial derivatives to manage exposure to fluctuations in ~~foreign currency exchange rates and~~ power prices. The Company does not utilize derivative financial instruments for trading purposes or for speculative purposes.

The Company’s derivative instruments are recorded at fair value with changes in fair value recognized in the Consolidated Statements of Operations at the end of each period in ~~Loss on foreign exchange~~ or Derivative (gain) loss.

Foreign Exchange Transactions

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Amounts held and transactions denominated in foreign currencies other than the operating unit’s functional currency give rise to foreign exchange gains and losses which are included within ~~Loss~~(Loss) gain on foreign ~~exchange.~~exchange

in the Consolidated Statements of Operations.

Foreign Currency Translation

The functional currency of the Company’s Canadian operations is the Canadian dollar. The Company’s Canadian operations’ assets and liabilities are translated at period end exchange rates, and revenues and costs are translated using average exchange rates for the period. Foreign currency translation adjustments are reported in Other comprehensive loss, net of income taxes. in the Consolidated Statements of Comprehensive Loss.

Reclassifications

Certain amounts in prior periods have been reclassified to conform with ~~the~~current year presentation, ~~of 2014,~~ with no effect on previously reported net loss, cash flows or shareholders’ deficit. ~~The reclassification affected accounts within current assets, current liabilities and noncurrent liabilities on the Consolidated Balance Sheet.~~

Recently Adopted Accounting Pronouncements

In ~~May 2014,~~October 2016, the Financial Accounting Standards Board ~~(FASB)~~("FASB") issued Accounting Standards Update ~~(ASU)~~(“ASU") 2016-16, Income Taxes (Topic 740): Intra-Entity Transfers of Assets Other than Inventory, which eliminates the exception that prohibits the recognition of current and deferred income tax effects for intra-entity transfers of assets other than inventory until the asset has been sold to an outside party. The new guidance is effective for fiscal years beginning after December 15, 2017, including interim periods within those fiscal years, with early adoption permitted. The amendments in this update should be applied on a modified retrospective basis through a cumulative-effect adjustment directly to accumulated deficit as of the beginning of the period of adoption. The Company early adopted this standard during the first quarter of 2017, which resulted in a cumulative effect adjustment as of January 1, 2017 reducing Other assets and Accumulated deficit by $0.4 million.

In March 2016, FASB issued ASU 2016-09, Compensation - Stock Compensation (Topic 718): Improvements to Employee Share-Based Payment Accounting. This guidance is designed to address simplification of several aspects of the accounting for share-based payment transactions, including the income tax consequences, classification of awards as either equity or liabilities and classification on the statement of cash flows. This guidance is effective for interim and annual periods beginning after December 15, 2016, and early adoption is permitted. Our January 1, 2017 retrospective adoption of this guidance did not have a material impact to our consolidated financial statements.

In July 2015, the FASB issued ASU 2015-11, Inventory (Topic 330): Simplifying the Measurement of Inventory,which simplifies the subsequent measurement of inventory by replacing the historical lower of cost or market test with a lower of cost or net realizable value test. This guidance is effective for interim and annual periods beginning after December 15, 2016. Our January 1, 2017 adoption of this guidance did not have a material impact to our consolidated financial statements.

Accounting Pronouncements Effective in the Future

In March 2017, the FASB issued ASU 2017-07, Compensation - Retirement Benefits (Topic 715): Improving the Presentation of Net Periodic Pension Cost and Net Periodic Postretirement Cost, which requires separate presentation of service costs and all other components of net benefit costs on the statement of operations. Under this ASU, service cost is included in the same line item as other compensation costs arising from services rendered by employees during the period, with all other components of net benefit costs on the statement of operations outside of income from operations. The new guidance is effective for fiscal years beginning after December 15, 2017, including interim periods within those fiscal years, with early adoption permitted. The amendments in this update require retrospective application. We will adopt the new guidance in the first quarter of 2018 and the adoption of this guidance will not have a material impact on the consolidated financial statements.

In August 2016, the FASB issued ASU 2016-15, Statement of Cash Flows (Topic 230): Classification of Certain Cash Receipts and Cash Payments, which standardizes cash flow statement classification of certain transactions, including cash payments for debt prepayment or extinguishment, proceeds from insurance claim settlements, and distributions received from equity method investments. The new guidance is effective for fiscal years beginning after December 15, 2017, including interim periods within those fiscal years, with early adoption permitted. The new guidance should be applied using a retrospective transition method to each period presented. If impracticable to apply the amendments retrospectively for some of the issues, the amendments for those issues would be applied prospectively as of the earliest date practicable. We will adopt the new guidance

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONT.)

in the first quarter of 2018 and the adoption of this guidance will not have a material impact on the consolidated financial statements.

In February 2016, the FASB issued ASU 2016-02, Leases (Topic 842), which requires companies leasing assets to recognize on their balance sheet a liability to make lease payments (the lease liability) and a right-of-use asset representing its right to use the underlying asset for the lease term on contracts longer than one year. The new guidance is effective for fiscal years beginning after December 15, 2018, using a modified retrospective approach, with early adoption permitted. The Company has established an implementation team to develop a multi-phase plan to adopt the requirements of the new standard. We will adopt the new guidance in the first quarter of 2019.

In May 2014, the FASB issued ASU 2014-09, Revenue from Contracts with Customers ~~issued as a new Topic, Accounting Standards Codification (ASC) Topic 606. The new~~(Topic 606), which supersedes all previously existing revenue recognition ~~standard provides a five-step analysis of transactions to determine when and how revenue is recognized. The core principle of the~~guidance. Under this guidance, ~~is that a company~~an entity should recognize revenue ~~to depict the transfer of~~when it transfers promised goods or services to customers in an amount that reflects the consideration to which the entity expects to be entitled in exchange for those goods or services. ~~This~~ ASU is2015-14, Revenue from Contracts with Customers (Topic 606): Deferral of the Effective Date, issued in August 2015, deferred the effective ~~beginning~~date of ASU 2014-09 to the first quarter of 2018, with early adoption permitted in ~~fiscal 2017~~the first quarter of 2017.

In March, April, May, and ~~can~~December 2016, the FASB issued the following updates, respectively, to provide supplemental adoption guidance and clarification to ASU 2014-09. These standards must be adopted byconcurrently upon the adoption of ASU 2014-09. We are currently evaluating the potential effects of adopting the provisions of these updates.

ASU 2016-08, Revenue from Contracts with Customers: Principal versus Agent Considerations (Reporting Revenue Gross versus Net);

ASU 2016-10, Revenue from Contracts with Customers: Identifying Performance Obligations and Licensing;

ASU 2016-12, Revenue from Contracts with Customers: Narrow-Scope Improvements and Practical Expedients; and

ASU 2016-19, Technical Corrections and Improvements

During 2016, the Company ~~either retrospectively~~established an implementation team to develop a multi-phase plan to assess the Company’s business and contracts, as well as any changes to processes or ~~as a cumulative-effect adjustment as~~systems to adopt the requirements of the new standard. As of the date of ~~adoption. The~~this filing, the Company ~~is currently evaluating~~has substantially completed its evaluation of the ~~effect that adopting this new accounting guidance will have on its consolidated results~~impact of ~~operations, cash flows and financial position.~~

~~In August 2014,~~ the ~~FASB issued ASU 2014-15 Presentation of Financial Statements—Going Concern (Subtopic 205-40): Disclosure of Uncertainties about an Entity’s Ability to Continue as a Going Concern. The~~ new standard ~~provides~~under the full retrospective approach. This process included a review of all material contracts, application of the new guidance ~~around management's responsibility~~ to ~~evaluate whether there is substantial doubt about an entity's ability to continue as a going concern~~each contract, and ~~to provide~~documentation of related ~~footnote disclosures. The~~conclusions. Based on our implementation team’s analyses, we have determined that the implementation of the new standard ~~is effective for fiscal years, and interim periods within those fiscal years, beginning after December 15, 2016. Early adoption is permitted. The adoption of this standard is not expected to~~will have a material impact on ~~the Company's~~our consolidated financial ~~statements.~~

~~Liquidity and Capital Resources~~

~~The Parent is a holding company and conducts its operations through subsidiaries. The Parent has significant cash requirements~~statements for long-term coal supply agreements in which we are entitled to ~~fund debt obligations, ongoing heritage health benefit~~payments from customers to reimburse our costs ~~pension contributions, and corporate overhead expenses. The principal sources of cash flow~~incurred during final reclamation as these payments relate to the ~~Parent~~only performance obligations within the contract, which consist of the sale of each ton of coal. As these estimates include significant uncertainty, we are ~~distributions~~still evaluating all assumptions used in the estimate and finalizing the amounts of accelerated revenues we will recognize for the years ended December 31, 2017 and 2016, and as of the transition date of January 1, 2016. The transition date adjustment will be made directly to accumulated deficit as of January 1, 2016, while the transition adjustments for the years ended December 31, 2017 and 2016 will restate previously reported revenues for those periods. These amounts will create a contract asset on our Consolidated Balance Sheets in the form of accounts receivable for final reclamation. Additionally, we are in the process of evaluating disclosure requirements, finalizing accounting policies and implementing changes to the relevant business processes and the control activities required to implement this standard.

2. ACQUISITIONS

Acquisition of San Juan

On January 31, 2016, WSJ, a variable interest entity of the Company, acquired SJCC, which operates the San Juan mine in Farmington, New Mexico, and San Juan Transportation Company (“SJTC” and such transaction, the “San Juan Acquisition”) for a total cash purchase price of $121.0 million after post-closing and working capital adjustments. The San Juan mine is the exclusive supplier of coal to the adjacent SJGS under a coal supply agreement through 2022. The San Juan operations are included in the Company’s Coal - U.S. segment.

WSJ financed the San Juan Acquisition principally with a $125.0 million loan from ~~its principal operating subsidiaries.~~NM Capital Utility Corporation (the “San Juan Loan”), an affiliate of Public Service Company of New Mexico (one of the owners of SJGS). The ~~cash~~loan is structured as a senior secured term loan (the “San Juan Loan”) maturing February 1, 2021 and is expected to bear interest at a (i) 7.25% rate (the “Margin Rate”) plus (ii) (A) the London Interbank Offered Rate for a three month period plus (B) a statutory

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~~all~~reserve rate, which such Margin Rate increases incrementally during each year of the San Juan Loan term with a final Margin Rate of 14.25% in the final year of the term. The San Juan Loan has no prepayment penalties. The agreements governing the San Juan Loan include representations and warranties and covenants regarding the ownership and operation of SJCC and the properties acquired in the Acquisition and standard special purpose bankruptcy remote entity covenants designed to preserve the separateness from Westmoreland of each of (i) WSJ, (ii) WSJ's direct parent company, Westmoreland San Juan Holdings, Inc., and (iii) the San Juan Entities ((i), (ii) and (iii) collectively, the “Westmoreland San Juan Entities”). Obligations under the San Juan Loan are recourse only to the Westmoreland San Juan Entities and their assets, and neither Westmoreland nor its subsidiaries (other than the Westmoreland San Juan Entities) is immediately available, except WRMI and WMLP. The cash at its captive insurance entity, WRMI, is available through dividends and is subject to maintaining a statutory minimum level of capital, which is two hundred fifty thousand dollars. The cash at WMLP is available through distributions. WMLP intends to resume quarterly distributions of $0.20 per unit beginning in April 2015, or $4.6 million annually. Based on the Company's current ownership of WMLP, the Company would expect to receive approximately 79% of WMLP’s distributions.

~~Under the Company's revolving credit agreement, the maximum available borrowing amount is $50 million, to which the maximum principal amount available for borrowings~~an obligor under the ~~credit~~San Juan Loan in any respect. The agreement ~~can be increased to $100 million under certain circumstances. The revolver may support an equal amount of letters of credit, which would reduce~~governing the ~~balance available under the revolver. At December 31, 2014, availability on the revolver was $16.9 million with an outstanding balance of $9.6 million and $23.5 million supporting letters of credit.~~

~~The Company anticipates~~San Juan Loan requires that with the $75 million increase to the Term Loan Facility that closed on January 22, 2015, cash from operations, cash on hand and available borrowing capacity will be sufficient to meet its investing, financing, and working capital requirements for the foreseeable future.


2.	~~ACQUISITIONS~~

~~Acquisition of General Partner of Westmoreland Resource Partners, LP~~

On December 31, 2014, the Company completed the acquisition of Westmoreland Resources GP, LLC, the general partner of Westmoreland Resource Partners, LP and completed a contribution of certain royalty-bearing coal reserves to WMLP in return for WMLP common units (the “Contribution”).

~~The completion~~all revenues of the ~~GP acquisition~~San Juan Entities, aside from payments on certain leases, are deposited into a cash management collection account swept monthly for operating expenses, capital expenditures, and ~~the Contribution provide Westmoreland with a platform to implement a value-creating drop-down strategy, pursuant to which it intends to periodically contribute certain U.S.~~San Juan Loan payment and Canadian coal assets to WMLP in exchange for a combination of cash and additional limited partner interests. Westmoreland expects these transactions to unlock value that is inherent in Westmoreland’s stable cash flow-generating business model, to the benefit of both its stakeholders and WMLP’s unitholders. WMLP will continue to operate as a standalone, publicly traded master limited partnership, with Westmoreland owning approximately 79% of the fully diluted limited partner interests. WMLP intends to resume quarterly distributions of $0.20 per unit beginning in April 2015, or $4.6 million annually. Based on the Company's current ownership of WMLP, it would expect to receive approximately 79% of WMLP’s distributions. In addition as WMLP's general partner, the Company is entitled to incentive distribution rights.prepayment.

Westmoreland paid $30.0 million in December, 2014 and $3.5 million in January, 2015 to acquire the GP; and received 4,512,500 common units of WMLP (on a post-split basis following a 12-to-1 reverse split of WMLP’s common and general partner units) as consideration for the Contribution.

In connection with certain mining permits relating to the ~~closing, the WMLP’s name was changed to Westmoreland Resource Partners, LP from Oxford Resource Partners, LP and the name~~operation of the ~~GP was changed to Westmoreland Resources GP, LLC from Oxford Resources GP, LLC. The common units~~San Juan mine, WSJ has posted reclamation bonds of ~~WMLP on~~$125.2 million with the ~~NYSE under the symbol “WMLP”.~~

~~Acquisition related costs of $4.5 million have been expensed for the year ended December 31, 2014 which are included in~~ ~~Selling~~New Mexico Mining and ~~administrative~~ ~~costs.~~Minerals Division.

The acquisition of the GP has been accounted for under the acquisition method of accounting that requires the total purchase consideration to be allocated to the assets acquired and liabilities assumed based on estimates of fair value.

The allocation of the purchase price is preliminary pending the completion of various analyses and the finalization of estimates. During the measurement period (which is not to exceed one year from the acquisition date), additional assets or liabilities may be recognized if new information is obtained about facts and circumstances that existed as of the acquisition date that, if known, would have resulted in the recognition of those assets or liabilities as of that date. The preliminary allocation may be adjusted after obtaining additional information regarding, among other things, asset valuations, liabilities assumed and revisions of previous estimates. These adjustments may be significant and will be accounted for retrospectively.

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~~WESTMORELAND COAL COMPANY AND SUBSIDIARIES~~

~~NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONT.)~~

~~A summary of the purchase consideration and a preliminary allocation of the purchase consideration follows (in millions):~~

Purchase Price:
Cash paid at closing $ 30.0
Contingent consideration 3.5
Fair value of outstanding WMLP units ⁽¹⁾
10.8
Total purchase consideration $ 44.3

Preliminary allocation of purchase price:
Assets:
     Trade receivables and other $ 22.5
     Inventories - materials and supplies 7.4
     Inventories - coal 6.6
     Other current assets 1.3
Total current assets 37.8
     Land and mineral rights 38.6
     Plant and equipment 134.0
     Advanced coal royalties 9.2
     Restricted investments and bond collateral 10.6
     Intangible assets 31.0
     Other assets 0.2
Total Assets 261.4
Liabilities:
     Trade payables and other accrued liabilities (19.1 )
     Asset retirement obligations (7.8 )
     Other current liabilities (4.0 )
Total current liabilities (30.9 )
     Long-term debt, less current installments (160.1 )
     Asset retirement obligations, less current portion (23.9 )
     Warrants (2.0 )
     Other liabilities (0.2 )
Total Liabilities (217.1 )
Net Assets 44.3
Non-controlling Interest (10.8 )
Invested Equity $ 33.5

~~(1) Represents the market price of WMLP units outstanding using the December 31, 2014 closing price of $1.00.~~

No goodwill was recorded in the acquisition and $31.0 million of intangible assets to be amortized over a 15-year period were identified in the acquisition. The intangible asset identified in the acquisition is a favorable terminal lease at a dock in Ohio which was fair valued based on more favorable market prices than contracted prices in lease agreements as measured during a business combination.

~~Canadian Acquisition~~

On December 24, 2013, the Company entered into an agreement to acquire Sherritt International Corporation’s Prairie and Mountain coal mining operations, collectively referred to as the Canadian Acquisition. On April 28, 2014, Westmoreland Coal Company consummated the Canadian Acquisition. These operations, referred to as the Canadian operations, include six producing thermal coal mines in the Canadian provinces of Alberta and Saskatchewan, a char production facility, and a 50%

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~~WESTMORELAND COAL COMPANY AND SUBSIDIARIES~~

~~NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONT.)~~

interest in an activated carbon plant. The purchase consideration included a $282.8 million initial cash payment made on April 28, 2014, a cash payment for a working capital adjustment of $39.8 million made on June 25, 2014, and assumed liabilities of $421.3 million.

~~Acquisition related costs of $33.6 million have been expensed for the year ended December 31, 2014; which include a $14.2 million charge to~~ ~~Cost of sales~~ ~~related to the sale of inventory written up to fair value in the acquisition, $8.3 million of expenses included in~~ ~~Selling and administrative~~ ~~costs, $6.2 million of loss on foreign exchange as described in Note 11, and $4.9 million included in~~ ~~Interest expense~~ ~~related to a bridge facility commitment fee.~~

~~The Canadian~~San Juan Acquisition has been accounted for under the acquisition method of accounting that requires the total purchase consideration to be allocated to the assets acquired and liabilities assumed based on estimates of fair value.

~~The Company has finalized the purchase~~ Purchase price ~~allocation for the Canadian Acquisition. No goodwill~~accounting was ~~recorded in the acquisition and $37.0 million~~considered final as of ~~intangible assets were identified in the acquisition.~~

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~~WESTMORELAND COAL COMPANY AND SUBSIDIARIES~~

~~NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONT.)~~

~~A summary of the purchase consideration and~~December 31, 2016. The allocation of the purchase consideration follows (in millions):

Provisional
as of
June 30,
2014
Adjustments
Final
as of
December 31,
2014
Purchase Price:
Cash paid - Initial payment $ 282.8
$ —
$ 282.8
Cash paid - Working capital adjustment 39.8
—
39.8
Total cash consideration $ 322.6
$ —
$ 322.6

Allocation of purchase price:
Assets:
     Cash and cash equivalents $ 26.2
$ —
$ 26.2
     Receivables 49.9
28.2
78.1
     Inventories - materials and supplies 52.0
—
52.0
     Inventories - coal 79.8
—
79.8
     Loan and lease receivables 11.2
—
11.2
     Deferred tax assets 6.7
1.5
8.2
     Other current assets 3.4
—
3.4
Total current assets 229.2
29.7
258.9
     Land and mineral rights 151.3
51.3
202.6
     Plant and equipment 139.6
(24.8 ) 114.8
     Loan and lease receivables 83.8
(4.7 ) 79.1
     Contractual third-party reclamation receivables, less current portion 6.8
—
6.8
Investment in joint venture 32.1
3.9
36.0
Intangible assets —
37.0
37.0
     Other assets 10.3
(1.6 ) 8.7
Total Assets 653.1
90.8
743.9
Liabilities:
     Current installments of long-term debt (36.3 ) —
(36.3 )
     Trade payables and other accrued liabilities (93.7 ) (42.4 ) (136.1 )
     Asset retirement obligations (9.7 ) 1.9
(7.8 )
Total current liabilities (139.7 ) (40.5 ) (180.2 )
     Long-term debt, less current installments (86.3 ) —
(86.3 )
     Asset retirement obligations, less current portion (92.4 ) (30.5 ) (122.9 )
     Deferred tax liabilities (12.1 ) (19.8 ) (31.9 )
Total Liabilities (330.5 ) (90.8 ) (421.3 )
Net fair value $ 322.6
$ —
$ 322.6



	Final as of December 31, 2016
Purchase price:
Cash paid	$	121.0

Allocation of purchase price:
Assets:
Inventories	8.8
Total current assets	8.8
Land and mineral rights	143.9
Plant and equipment	74.6
Other assets	1.3
Total assets	228.6
Liabilities:
Trade payables and other accrued liabilities	13.4
Production taxes	2.0
Asset retirement obligations	0.7
Total current liabilities	16.1
Asset retirement obligations, less current portion	43.5
Postretirement medical benefits	1.9
Deferred income taxes	46.1
Total liabilities	107.6
Net fair value	$	121.0

The $26.2 million of cash and cash equivalents noted above includes $18.1 million which was used for immediate payment of an assumed liability on the acquisition date, leaving $8.1 million of net cash received upon the acquisition.

During the third quarter of 2014, the Company transferred to an unrelated third party the contract related to the $37.0 million intangible asset noted above. Proceeds of $37.0 million were received from the unrelated third party, with no gain or loss recognized on the transaction.

The Company became responsible for remediation work for a breach on a containment pond at a currently inactive mine that occurred on October 31, 2013. The prior owner, Sherritt International Corporation, has indemnified Westmoreland

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~~WESTMORELAND COAL COMPANY AND SUBSIDIARIES~~

~~NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONT.)~~

~~against past and future liability stemming from the incident. Accordingly, an indemnification asset of $27.9 million and a corresponding liability was recorded at April 28, 2014.~~

The results of operations of the Canadian operations from the acquisition date of April 28, 2014 have been included in the Company’s consolidated results of operations for the year ended December 31, 2014. The Canadian operations generated $388.7 million of revenue and $2.7 million of operating loss since the April 28, 2014 acquisition date.

Unaudited Pro Forma Information

The following unaudited pro forma information has been prepared for illustrative purposes only and assumes the ~~acquisition of the GP and the Canadian~~San Juan Acquisition occurred on January 1, ~~2013.~~2015. The unaudited pro forma results have been prepared based on estimates and assumptions, which the Company believes are reasonable, however, they are not necessarily indicative of the ~~consolidated results~~Consolidated Statements of ~~operations~~Operations had the acquisitions occurred on ~~January 1, 2013,~~the dates indicated above, or of future results of operations.

Years Ended
December 31, 2014 December 31, 2013
(In thousands)
Total Revenues
As reported $ 1,115,992
$ 674,686
Pro forma (unaudited) $ 1,644,474
$ 1,673,538

Operating Income (Loss)
As reported $ (42,975 ) $ 25,362
Pro forma (unaudited) $ (38,827 ) $ 36,097
��
Net loss applicable to common shareholders
As reported $ (173,118 ) $ (6,057 )
Pro forma (unaudited) $ (135,647 ) $ (62,595 )

Net loss per share applicable to common shareholders
As reported $ (10.86 ) $ (0.42 )
Pro forma (unaudited) $ (8.51 ) $ (4.32 )
Due to the full year of ownership in 2017, no pro forma information has been presented below for the year ended December 31, 2017.


3.	~~INVENTORIES~~

~~Inventories consisted of the following:~~

December 31,
2014 2013
(In thousands)
Coal stockpiles $ 41,795
$ 543
Coal fuel inventories 6,531
6,161
Materials and supplies 88,584
34,233
Reserve for obsolete inventory (3,055 ) (965 )
Total $ 133,855
$ 39,972

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4.	~~RESTRICTED INVESTMENTS AND BOND COLLATERAL~~

~~The Company’s restricted investments and bond collateral consist of the following:~~

December 31,
2014 2013
(In thousands)
Coal - U.S. Segment:
WML debt reserve account $ —
$ 13,067
Reclamation bond collateral:
Kemmerer Mine 25,282
24,966
Absaloka Mine 11,781
11,653
Rosebud Mine 3,145
3,145
Beulah Mine 1,270
1,270
Buckingham acquisition escrow 34,000
—
Coal - Canada Segment:
PMRU 18,199
—
CVRI 31,866
—
Coal - WMLP Segment:
WMLP 10,634
—
Power Segment:
Letter of credit account —
5,998
Power contract collateral 12,600
—
Corporate Segment:
Postretirement medical benefit bonds 8,780
8,467
Workers’ compensation bonds 6,832
6,667
Total restricted investments and bond collateral 164,389
75,233
Less current portion —
(5,998 )
Total restricted investments and bond collateral, less current portion $ 164,389
$ 69,235



	Years Ended December 31,
	2016			2015
	(In thousands, except per share data)
Total revenues
As reported	$	1,477,960		$	1,419,518
Pro forma (unaudited)	1,504,235			1,714,043

Operating income (loss)
As reported	$	38,130		$	(145,696	)
Pro forma (unaudited)	39,225			(106,606		)

Net loss applicable to common shareholders
As reported	$	(27,101	)	$	(213,645	)
Pro forma (unaudited)	(26,676		)	(187,139		)

Net loss per share applicable to common shareholders, basic & diluted
As reported	$	(1.47	)	$	(11.93	)
Pro forma (unaudited)	(1.44		)	(10.45		)

~~For~~Kemmerer Drop

On August 1, 2015, we contributed 100% of the outstanding equity interests in Westmoreland Kemmerer, LLC (“Kemmerer”) to WMLP in exchange for $230 million in aggregate consideration, comprised of $115 million in cash and $115 million in newly issued WMLP Series A Convertible Units (the “Series A Units” and such transaction, the “Kemmerer Drop”). In connection with the Kemmerer Drop, all employees of ~~its restricted investments~~Kemmerer and ~~bond collateral accounts,~~related employee liabilities, including but not limited to postretirement pension obligations and postretirement health benefits, were transferred to the Parent. The Series A Units are convertible into common units representing limited partner interests of WMLP (“Common Units”), on a one-for-one basis, upon the earlier of (i) the date on which WMLP first makes a regular quarterly cash distribution to holders of Common Units in an amount equal to at least $0.22 per Common Unit, or (ii) a change of control of WMLP. Following the Kemmerer Drop, at December 31, 2017 we held an approximately 93.94% controlling interest in WMLP (on a fully diluted basis). The Kemmerer Drop represents a reorganization of entities under common control. Accordingly, the net assets transferred are deemed to have transferred at the $102.6 million carrying value as of the date of transfer. No gain or loss was recognized.

3. VARIABLE INTEREST ENTITY

As of December 31, 2017, the Company ~~can select from limited fixed-income investment options~~consolidated its 100% owned WSJ subsidiary which is a variable interest entity (“VIE”). WSJ’s classification as a VIE is due to another party having the potential right to receive WSJ’s residual returns. The Company is the primary beneficiary because it has the power to direct the activities that most significantly impact WSJ’s economic performance. Accordingly, the Company consolidated the operating results, assets and liabilities of WSJ. See Note 2 - Acquisitions and Note 8 - Debt And Lines Of Credit to the consolidated financial statements.

The following table presents the carrying amounts, after eliminating the effect of intercompany transactions, included in the Consolidated Balance Sheets that are for the ~~funds and receive~~use of or are the ~~investment returns on these investments. Funds in the restricted investments and bond collateral accounts are not available to meet the Company’s general cash needs.~~obligation of WSJ (in thousands):

~~These accounts include available-for-sale securities. Available-for-sale securities are reported at fair value with unrealized gains and losses excluded from earnings and reported in~~ ~~Accumulated other comprehensive loss~~.



	December 31, 2017		December 31, 2016
Assets	$	203,737	$	268,910
Liabilities	167,529		243,884
Net carrying amount	$	36,208	$	25,026

~~The cost basis of an investment sold is specifically identified.~~

~~During~~4. LOSS ON IMPAIRMENT

For the year ended December 31, ~~2014, the Company decided~~2017, we recorded an impairment charge of $5.9 million related to ~~more actively manage its investment yields. This decision resulted~~land and mineral rights in ~~the sale of $5.1 million carrying value of securities and realized gains of less than $0.1 million during the year ended December 31, 2014 that~~Kentucky within our Coal - WMLP segment which were ~~previously designated as held-to-maturity. The Company transferred the remainder of its securities classified as held-to-maturity~~determined to ~~available-for-sale securities. The carrying value of held-to-maturity securities held as~~ ~~Restricted investments and bond collateral~~ ~~transferred to available-for-sale during the year ended December 31, 2014 was $34.5 million. As a result of the transfer, the Company recorded $0.6 million of unrealized holding gains in~~ ~~Accumulated other comprehensive loss~~ ~~during the year ended December 31, 2014.~~have no further economic value.

~~The Company’s carrying value and estimated fair value of its restricted investments and bond collateral at~~ ~~December 31, 2014~~ ~~are as follows:~~

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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, and resided in our Power segment. 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 Loss on impairment in the Consolidated Statements of Operations for the year ended December 31, 2015. Our fair value measurement for these assets was determined based on a probability-weighted estimate of discounted future cash flows, which are Level 3 fair value measurements. Key inputs to the fair value measurement for these assets included current forecasted electricity prices in the region ROVA serves, which we believe will continue to remain at depressed levels, as well as forecasted cost inputs based on the Company’s planning and budgeting process.

We also recorded an impairment charge of $3.1 million to the same line item in the Consolidated Statements of Operations during the year ended December 31, 2015 for certain immovable fixed assets at our Coal Valley mine, which is part of the Coal-Canada segment, primarily as a result of continued declines in pricing in the export markets which Coal Valley serves.

5. INVENTORIES

Inventories consisted of the following:

Carrying Value Fair Value
(In thousands)
Cash and cash equivalents $ 127,881
$ 127,881
Time deposits 2,451
2,451
Available-for-sale 34,057
34,057
$ 164,389
$ 164,389



	December 31, 2017			December 31, 2016
	(In thousands)
Coal stockpiles	$	38,145		$	44,692
Materials and supplies	73,517			84,444
Reserve for obsolete inventory	(4,867		)	(3,621		)
Total	$	106,795		$	125,515

In 2014, 2013, and 2012, the Company recorded a gain of $0.3 million, less than $0.1 million, and $0.1 million, respectively, on the sale of available-for-sale securities held as restricted investments and bond collateral.

~~The $6.0 million letter of credit account in the power segment was released from restriction in February, 2014.~~

6. RESTRICTED INVESTMENTS, RECLAMATION DEPOSITS AND BOND COLLATERAL

Coal ~~Segments~~

~~As of~~ ~~December 31, 2014, the Company had reclamation~~segments maintain government-required bond collateral ~~in place for the individual Mines as required. These government-required bonds assure~~ that ~~coal-mining operations comply~~assures compliance with applicable federal and state regulations relating to the performance ~~and completion~~ of final reclamation activities. The amounts deposited in the bond collateral account secure the bonds issued by the bonding company.

~~Power Segment~~

~~As of February, 2014, the Company was no longer required to fund a letter of credit account for its power operations.~~ The ~~Company will periodically need to fund a power contract collateral account related to its contracts to purchase power.~~

Corporate ~~Segment~~

~~The Company~~segment is required to obtain surety bonds in connection with its self-insured workers’ compensation plan and certain health care plans. The Company’s surety bond underwriters require collateral to issue these bonds.

~~Held-to-Maturity and Available-for-Sale Restricted Investments and Bond Collateral~~ Prior to December 31, 2017, the Power segment was required to maintain a collateral account related to its contracts to purchase power.

The ~~amortized cost, gross~~Company invests certain bond collateral, reclamation deposits and other restricted investments in a limited selection of fixed-income investment options and receives the corresponding investment returns. These investments are not available to meet the Company’s general cash needs. These investments include available-for-sale securities, which are reported at fair value with unrealized ~~holding~~ gains and losses excluded from earnings and reported in Accumulated other comprehensive loss in the Consolidated Balance Sheets. On disposal, the resulting gain or loss is reported in Other (loss) income in the Consolidated Statements of Operations.

The Company’s carrying value and estimated fair value of ~~held-to-maturity securities are~~Restricted investments, reclamation deposits and bond collateral as of December 31, 2017 were as follows:

December 31,
2014 2013
(In thousands)
Amortized cost $ —
$ 32,184
Gross unrealized holding gains —
309
Gross unrealized holding losses —
(447 )
Fair value $ —
$ 32,046



	Restricted Investments and Bond Collateral		Reclamation Deposits		Total Restricted Investments, Reclamation Deposits and Bond Collateral
	(In thousands)
Cash and cash equivalents	$	42,549	$	6,643	$	49,192
Time deposits	2,467		—		2,467
Available-for-sale	78,157		70,378		148,535
	$	123,173	$	77,021	$	200,194

~~The cost basis, gross unrealized holding gains and fair value of available-for-sale securities are as follows:~~

December 31,
2014 2013
(In thousands)
Cost basis $ 33,879
$ —
Gross unrealized holding gains 761
—
Gross unrealized holding losses (583 ) —
Fair value $ 34,057
$ —

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONT.)

The Company’s carrying value and estimated fair value of its Restricted investments, reclamation deposits and bond collateral as of December 31, 2016 were as follows:



	Restricted Investments and Bond Collateral		Reclamation Deposits		Total Restricted Investments, Reclamation Deposits and Bond Collateral
	(In thousands)
Cash and cash equivalents	$	66,860	$	2,673	$	69,533
Time deposits	2,473		—		2,473
Available-for-sale	75,580		71,689		147,269
	$	144,913	$	74,362	$	219,275

Available-for-Sale Restricted Investments

The cost basis, gross unrealized holding gains and losses, and fair value of available-for-sale securities as of December 31, 2017 were as follows:



	Restricted Investments and Bond Collateral			Reclamation Deposits			Total Restricted Investments, Reclamation Deposits and Bond Collateral
	(In thousands)
Cost basis	$	78,564		$	70,576		$	149,140
Gross unrealized holding gains	521			617			1,138
Gross unrealized holding losses	(928		)	(815		)	(1,743		)
Fair value	$	78,157		$	70,378		$	148,535

The cost basis, gross unrealized holding gains and losses, and fair value of available-for-sale securities as of December 31, 2016 were as follows:



	Restricted Investments and Bond Collateral			Reclamation Deposits			Total Restricted Investments, Reclamation Deposits and Bond Collateral
	(In thousands)
Cost basis	$	76,558		$	72,381		$	148,939
Gross unrealized holding gains	251			453			704
Gross unrealized holding losses	(1,229		)	(1,145		)	(2,374		)
Fair value	$	75,580		$	71,689		$	147,269

Maturities of available-for-sale securities were as follows ~~at December 31, 2014:~~

Amortized Cost Fair Value
(In thousands)
Due within one year $ 327
$ 331
Due in five years or less 13,961
13,996
Due after five years to ten years 11,323
11,440
Due in more than ten years 8,268
8,290
$ 33,879
$ 34,057


5.	~~RESTRUCTURING CHARGES~~

In 2013, the Company entered into an agreement with Dominion Virginia Power, a subsidiary of Dominion, to renegotiate the remaining 5 years of the ROVA contract. The Company recorded a restructuring charge for additional contractual obligations of $0.5 million for the year ended December 31, 2014. The Company expects that the $0.4 million of accruals as of December 31, ~~2014 will be paid out in first quarter of 2015.~~2017:

~~The table below represents~~



	Cost Basis		Fair Value
	(In thousands)
Due within one year	$	13,960	$	13,423
Due in five years or less	60,827		60,447
Due after five years to ten years	32,381		32,527
Due in more than ten years	41,972		42,138
	$	149,140	$	148,535

For the ~~restructuring provision activity related to the ROVA restructuring affecting our Power segment during the year~~years ended December 31, ~~2014 (in millions):~~

Beginning Balance Restructuring Charges Restructuring Payments Ending Balance
$ 5.1
$ 0.5
$ 5.2
$ 0.4

~~During 2014,~~2017, 2016, and 2015, the Company ~~initiated strategic changes related to~~recorded realized (losses) gains of $(0.3) million, $0.2 million, and $0.1 million, respectively, on the Canadian Acquisition and the Westmoreland Resources GP, LLC Acquisition. The restructuring actions were completed in 2014 for the Canadian Acquisition and are expected to be completed in 2015 for the Westmoreland Resources GP, LLC Acquisition. The Company recorded restructuring charges for one-time employee termination benefitssale of ~~$14.5 million for the year ended December 31, 2014 and expects that accruals will be paid through 2016.~~

The table below represents the restructuring provision activity related to the Canadian Acquisition and the Westmoreland Resources GP, LLC Acquisition affecting our Coal - Canada, Coal - U.S. and Coal - WMLP segments during the year ended December 31, 2014 (in millions):

Beginning Balance Restructuring Charges Restructuring Payments Ending Balance
$ —
$ 14.5
$ 5.7
$ 8.8
available-for-sale securities.

~~100~~91

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONT.)


6.	~~LINES OF CREDIT AND LONG-TERM DEBT~~

~~The amounts outstanding under~~7. INTANGIBLE ASSETS AND LIABILITIES

Identifiable intangible assets acquired in a business combination are specifically identified and recognized on a standalone basis. Intangible assets result from more favorable contract prices than market prices in lease agreements as measured during a business combination. As a result of prior period acquisitions, we determined that the ~~Company’s long-term debt consisted~~most significant acquired identifiable intangible assets are related to favorable lease agreements. These intangible assets are recorded in Other assets on our Consolidated Balance Sheets and are amortized on a straight-line basis over the remaining terms of the ~~following~~lease agreements.



	December 31, 2017
	Estimated Remaining Life (years)	Cost		Accumulated Amortization		Net Carrying Value
	(In thousands except for years data)
Favorable lease agreements	12	$	32,174	$	6,327	$	25,847



	December 31, 2016
	Estimated Remaining Life (years)	Cost		Accumulated Amortization		Net Carrying Value
	(In thousands except for years data)
Favorable lease agreements	13	$	32,174	$	4,142	$	28,032

Amortization of intangible assets recognized in Depreciation, depletion and amortization was $2.2 million, $2.2 million and $2.1 million for the years ended December 31, 2017, 2016 and 2015, respectively.

Our intangible liabilities resulted from our acquisition, as part of a business combination, of contracts with terms that were unfavorable to prevailing market prices at the time of acquisition. Amortization of intangible liabilities recognized in Revenues in the Consolidated Statements of Operations was $0.9 million for the years ended December 31, 2017, 2016 and 2015. During the fourth quarter of 2017 we disposed of our ROVA segment operations as well as all associated intangible liabilities. As such, no further amortization of these intangible liabilities into Revenues will occur in future periods.

The intangible assets and liabilities are generally amortized straight-line over the life of the related contracts. The estimated amortization amounts from intangibles assets for each of the next five years as of ~~the dates indicated:~~December 31, 2017 are as follows:

Total Debt Outstanding
December 31,
2014 2013
(In thousands)
8.75% senior secured notes due 2021 $ 350,000
$ —
Term loan facility due 2020 350,000
—
WMLP term loan facility due 2018 175,000
—
10.75% senior notes —
251,500
8.02% WML term debt —
85,500
Capital lease obligations 109,351
10,153
Revolving line of credit 9,576
—
Other 4,062
1,209
Debt discount (13,202 ) (8,525 )
Total debt outstanding 984,787
339,837
Less current installments (52,712 ) (44,343 )
Total debt outstanding, less current installments $ 932,075
$ 295,494



	Amount of Amortization to Recognize in Expense

2018	$	2,184
2019	2,184
2020	2,184
2021	2,184
2022	2,184

8. DEBT AND LINES OF CREDIT

The Company and its subsidiaries are subject to the following debt arrangements:

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WESTMORELAND COAL COMPANY AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONT.)



	Issuance Amount	Issuance Date	Maturity Date	Total Debt Outstanding
	Issuance Amount	Issuance Date	Maturity Date	December 31, 2017			December 31, 2016
	(In millions)	(MM/DD/YY)	(MM/DD/YY)	(In thousands)
8.75% Notes	$350.0	12/16/14	1/1/22	$	350,000		$	350,000
Term Loan	425.0	12/16/14	12/16/20	320,595			323,883
San Juan Loan	125.0	2/1/16	2/1/21	56,640			95,000
WMLP Term Loan	295.0	12/31/14	12/31/18	312,734			306,189
Revolver	*	12/16/14	12/31/18	—			—
Capital lease obligations	Varies	Varies	Varies	33,113			55,061
Other debt	Varies	Varies	Varies	2,826			16,464
Total debt				1,075,908			1,146,597
Less debt discount and issuance costs, net				(27,501		)	(37,531		)
Less current installments, net of debt discount and issuance costs				(983,427		)	(86,272		)
Total non-current debt				$	64,980		$	1,022,794

____________________

* Not applicable.

The following table presents aggregate contractual debt maturities of all long-term ~~debt:~~debt as of December 31, 2017 (in thousands):

As of December 31, 2014
(In thousands)
2015 $ 52,712
2016 41,489
2017 31,435
2018 183,848
2019 5,808
Thereafter 682,697
Total 997,989
Less: debt discount (13,202 )
Total debt $ 984,787



Maturity Date⁽¹⁾	Debt Held by WMLP		All Other Debt		Total Debt Outstanding
2018	$	316,982	$	21,345	$	338,327
2019	4,175		17,263		21,438
2020	1,768		339,548		341,316
2021	1,664		21,165		22,829
2022	1,998		350,000		351,998
Thereafter	—		—		—
Total debt	$	326,587	$	749,321	$	1,075,908

_________________

(1) Debt obligations are scheduled based on their contractual maturities and are not reflective of any potential accelerations discussed further below.

Covenant Compliance

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WESTMORELAND COAL COMPANY AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONT.)

things, the calculation of Canadian EBITDA as it is used in the fixed charge coverage ratio. The amendment removed certain financial results attributable to the Coal Valley mine from Canadian EBITDA and results in our compliance with the covenant for the year ended December 31, 2017. Absent this amendment we would have failed to satisfy the financial covenant. The amendment also waives any covenant violation for the year ended December 31, 2017 that solely results from the receipt of an opinion from our independent registered public accounting firm that includes an explanatory paragraph referencing WCC’s conclusion that substantial doubt exists as to WCC’s ability to continue as a going concern.

8.75% Notes ~~Offering~~

OnPursuant to our senior note indenture, dated as of December 16, 2014, ~~(the “Closing Date”),~~by and among the Company, ~~completed~~ the ~~issuance of $350.0 million in aggregate principal amount of 8.75% Notes. The~~guarantors named therein, and U.S. Bank National Association, as trustee and notes collateral agent (the “Indenture”), our senior secured 8.75% Notes (“8.75% Notes”) were issued at a 1.292% discount ~~mature on January 1, 2022,~~ and bear a fixed interest rate of 8.75% payable semiannually, on January 1 and July 1 of each year, commencing July 1, 2015. The 8.75% Notes are a primary obligation of the Company and are guaranteed by Westmoreland Energy LLC, Westmoreland Mining LLC and Westmoreland Resources, Inc. and their respective subsidiaries (other than Absaloka Coal, LLC, Westmoreland Risk Management, Inc. and certain other immaterial subsidiaries), referred to as the “Guarantors.” The 8.75% Notes are not guaranteed by Westmoreland Canada LLC or any of its subsidiaries, Westmoreland San Juan, LLC or any of its subsidiaries, or Westmoreland Resources GP, LLC or WMLP, referred to as the “Non-guarantors.”

The 8.75% Notes are the Company’s senior secured obligations, rank equally in right of payment with all of the Company’s existing and future senior obligations, including the Term Loan ~~Credit Facility Obligations defined~~(defined below under “Term ~~Loan Credit Agreement,”~~Loan”) and rank senior to all of the Company’s existing and future indebtedness that is expressly subordinated to the 8.75% Notes. The 8.75% Notes have not been registered under the Securities Act of 1933. ~~Proceeds from the~~The 8.75% Notes offering and borrowing on the Term Loan Credit Agreement were used to repay the outstanding 10.75% senior notes with a principal balance of $675.5 million. As a result of the extinguishment of the 10.75% senior notes, the Company recorded a $34.9 million loss on extinguishment of debt.contain certain customary cross-default provisions. In 2014, the Company capitalized debt issuance costs of $10.2 million in connection with the 8.75% Notes.

The Company may redeem all or part of the 8.75% Notes beginning on January 1, 2018 at the redemption prices set forth in the ~~Indenture,~~8.75% Notes agreement, and prior to January 1, 2018 at 100% of the principal amount plus the applicable premium described in the ~~Indenture.~~8.75% Notes agreement. In addition, at any time prior to January 1, 2018, the Company may redeem up to 35% of the aggregate principal amount of the 8.75% Notes with the net cash proceeds of certain equity offerings at a redemption price equal to 108.75% of the

~~101~~

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~~NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONT.)~~

principal amount ~~of the 8.75% Notes~~ to be redeemed, together with accrued and unpaid interest, if any, to the redemption date, subject to certain conditions.

The 8.75% Notes are guaranteed by Westmoreland Energy LLC, Westmoreland Kemmerer, Inc., Westmoreland Mining LLC and Westmoreland Resources, Inc. and their respective subsidiaries (other than Absaloka Coal, LLC, Westmoreland Risk Management, Inc. and certain other immaterial subsidiaries). The 8.75% Notes are not guaranteed by Westmoreland Canada LLC or any of its subsidiaries, nor are they guaranteed by Westmoreland Resources GP, LLC or Westmoreland Resource Partners, LP, referred to as the Non-guarantors.

~~The 8.75% Notes~~ and the guarantees are secured equally and ratably with the Term Loan ~~Credit Agreement~~ (i) by first priority liens on substantially all of the Company’s and the guarantor parties’ tangible and intangible assets (excluding certain equity interests, mineral rights and sales contracts and certain assets subject to existing liens) and (ii) subject to the ~~Revolving Credit Agreement~~Revolver (as defined below), a second priority lien on substantially all cash, accounts receivable and inventory of the Company and the guarantors, and any other property with respect to, evidencing or relating to such cash, accounts receivable and inventory (whether now owned or hereinafter arising or acquired) and the proceeds and products thereof, subject in each case to permitted liens and certain exclusions (the “Notes Collateral”). The Notes Collateral is shared equally with the lenders under the Term Loan, ~~Credit Agreement,~~ who hold identical first and second priority liens, as applicable, on the Notes Collateral.

The ~~Indenture restricts~~8.75% Notes restrict the Company’s and its restricted subsidiaries’ ability to, among other things, (i) incur, assume or guarantee additional indebtedness or issue preferred stock; (ii) declare or pay dividends on, or make other distributions in respect of, their capital stock; (iii) purchase or redeem or otherwise acquire for value any capital stock or subordinated indebtedness; (iv) make investments, other than permitted investments; (v) create certain liens or use assets as security; (vi) enter into agreements restricting the ability of any restricted subsidiary to pay dividends, make loans, or any other distributions to the Company or other restricted subsidiaries; (vii) engage in transactions with affiliates; and (viii) consolidate or merge with or into other companies or transfer all or substantially all of their assets.

The ~~Indenture contains, among other provisions,~~8.75% Notes contain customary affirmative covenants, negative covenants, events of default, ~~and various affirmative and negative covenants. As~~as well as certain customary cross-default provisions. Our compliance or non-compliance with these covenants is discussed above.

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONT.)

Term Loan

Pursuant to our credit agreement, dated as of December ~~31,~~22, 2014, by and among the Company, ~~was in compliance with all covenants for these Notes.~~

the lenders from time to time party thereto, and Bank of Montreal, as administrative agent, as amended (“Term ~~Loan Credit Agreement~~

~~Effective as of~~Loan”), the ~~Closing Date, the Company entered into a term loan credit agreement (the “Term Loan Credit Agreement”) which provides for a~~ $350.0 million ~~term loan facility (the “Term Loan”) with a single advance made on the Closing Date. The~~ Term Loan was issued at a ~~2.5%~~2.50% discount and ~~matures~~accrues interest on ~~December 16, 2020. Borrowings under the Term Loan will initially bear~~a quarterly basis at a variable interest rate which is set at ~~one-month~~our election of (i) one-, two-, three- or six-month London Interbank Offered Rate (“LIBOR”) plus 6.50% or (ii) a base rate (determined with reference to the highest of the prime rate, the Federal Funds Rate plus 0.05%, or one-month LIBOR plus 1.00%) plus 5.50%. ~~The~~As of December 31, 2017, the cash interest rate ~~at December 31, 2014~~ was ~~7.50%~~8.19%. In 2014, the Company capitalized debt issuance costs of $8.4 million in connection with the Term Loan.

The Term Loan Credit Agreement contains customary affirmative covenants, negative covenants, and events of default. Pursuant to the terms and provisions of the Guaranty and Collateral Agreement, dated the Closing Date, the obligations under the Term Loan are secured by identical first and second priority liens, as applicable, on the Notes Collateral. As of December 31, 2014, the Company was in compliance with all covenants for the Term Loan.

~~The Term Loan~~ is guaranteed by Westmoreland Energy LLC, ~~Westmoreland Kemmerer, Inc.,~~ Westmoreland Mining LLC, Westmoreland Resources, Inc. and certain other direct and indirect subsidiaries of the Company (other than Absaloka Coal, LLC, Westmoreland Risk Management, Inc., Westmoreland Canada, LLC, Westmoreland Resources GP, LLC, Westmoreland Resource Partners, LP and certain other immaterial subsidiaries).

~~Add-on~~ The obligations under the Term Loan are secured by identical first and second priority liens, as applicable, on the Notes Collateral.

The Term Loan contains customary affirmative covenants, negative covenants, events of default, as well as certain customary cross-default provisions. Our compliance or non-compliance with these covenants is discussed above.

Term Loan Add-on

On January 22, 2015, the Company amended the Term Loan ~~Credit Agreement~~ to increase the borrowings by $75.0 million, for an aggregate principal amount of $425.0 ~~million.~~million as of that date. The amendments to the Term Loan ~~Credit Agreement~~ were made in connection with the acquisition of Buckingham Coal Company, LLC. Net proceeds were $71.0 million after a ~~2.5%~~2.50% discount, ~~1.5%~~1.50% broker fee, a consent fee of 1.17%, and $0.1 million of additional debt issuance costs. With this addition, the quarterly principal payment due commencing March 31, 2015 is $1.1 million. Under the Term Loan, we are required to offer a portion of our excess cash flows for each fiscal year, beginning with the fiscal year ended December 31, 2015.

~~Revolving Credit Agreement~~

~~During~~In conjunction with the ~~first quarter of 2014,~~Kemmerer Drop, the Company amended ~~its existing revolving credit~~the Term Loan to remove Kemmerer as a guarantor. In addition, $94.1 million of the proceeds received from WMLP related to the Kemmerer Drop were used to pay down the Term Loan.

San Juan Loan

On January 31, 2016, Westmoreland San Juan, LLC (“WSJ”), a special purpose subsidiary of Westmoreland, acquired San Juan Coal Company (“SJCC”), which operates the San Juan mine in Farmington, New Mexico, and San Juan Transportation Company (the “San Juan Acquisition”) for a total cash purchase price of $121.0 million after customary post-closing adjustments. The San Juan mine is the exclusive supplier of coal to the adjacent San Juan Generating Station (“SJGS”) under a coal supply agreement with tonnage and pricing adjusting quarterly through 2022. WSJ financed the San Juan Acquisition in part with a senior secured $125.0 million loan (“San Juan Loan”) pursuant to ~~increase~~ the ~~maximum available borrowing amount to $60.0 million. On December 16, 2014,~~loan agreement, dated as of February 1, 2016, by and among WSJ and the remaining Westmoreland San Juan Entities as guarantors, and NM Capital Utility Corporation (an affiliate of Public Service Company ~~further amended~~of New Mexico, part owner of SJGS) as lender. The San Juan Loan was issued at a 6.70% discount, incurred $3.1 million of debt issuance costs and pays interest and principal on a quarterly basis at an interest rate of (i) the ~~revolving credit agreement, or~~Margin Rate of 7.25% plus (ii) (A) the ~~Second Amended and Restated~~LIBOR for a three month period plus (B) a statutory reserve rate, which such Margin Rate increases incrementally during each year of the San Juan Loan ~~Agreement, decreasing the maximum borrowing amount to $50.0 million~~term with a final Margin Rate of 14.25% in the ~~aggregate, consisting~~final year of ~~a $30.0 million sub-facility available~~the term. As of December 31, 2017, the cash interest rate was 10.63%. In addition, in the ~~U.S.~~event the loan is not paid off prior to maturity, the price of the coal in our coal supply agreement decreases by 10% after January 1, 2019 and ~~a $20.0 million sub-facility~~15% after January 1, 2021.

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The San Juan Loan is a primary obligation of Westmoreland San Juan, LLC, is guaranteed by SJCC, and is secured by substantially all of SJCC’s assets. The San Juan Loan has no prepayment penalties. The agreements governing the San Juan Loan include representations and warranties and covenants regarding the ownership and operation of SJCC and the properties acquired in the San Juan Acquisition and standard special purpose bankruptcy remote entity covenants designed to preserve the separateness from Westmoreland of each of (i) WSJ, (ii) its direct parent company, Westmoreland San Juan Holdings, Inc., (iii) SJCC and (iv) SJTC (collectively, the “Westmoreland San Juan Entities”). Obligations under the San Juan Loan are recourse only to the Westmoreland San Juan Entities and their assets. Westmoreland nor its subsidiaries (other than the Westmoreland San Juan Entities) is an obligor under the San Juan Loan in any respect. The agreement governing the San Juan Loan requires that all revenues of the Westmoreland San Juan Entities, aside from payments on certain leases, are deposited into a cash management collection account swept monthly for operating expenses, capital expenditures, and loan payment and prepayment. The assets and credit of SJCC are not available to satisfy the debts and other obligations of the Company other than those of the Westmoreland San Juan Entities.

The San Juan Loan contains customary affirmative covenants and negative covenants. Our compliance or non-compliance with these covenants is discussed above.

WMLP Term Loan

Pursuant to the financing agreement, dated as of December 31, 2014, by and among Oxford Mining Company, LLC, WMLP and each of its subsidiaries, lenders from time to time party thereto, and U.S. Bank National Association, as administrative agent, WMLP entered into a term loan (“WMLP Term Loan”) which consists of a $175.0 million, with an option for an additional $120.0 million in ~~Canada.~~term loans for acquisitions, which was exercised on August 1, 2015 to finance the Kemmerer Drop. Proceeds from the credit facility were used to retire WMLP’s previously existing first and second lien credit facilities and to pay fees and expenses related to its existing credit facility, with the remaining proceeds being available as working capital. The ~~maximum~~WMLP Term Loan was not issued at a discount or a premium and $8.6 million of debt issuance costs were recognized at December 31, 2014. The WMLP Term Loan pays interest on a quarterly basis and bears interest at a variable rate equal to the 3-month LIBOR at each quarter end (1.69% as of December 31, 2017), subject to a floor of 0.75%, plus 8.50% or the Reference Rate, as defined in the financing agreement. As of December 31, 2017, the WMLP Term Loan had a cash interest rate of 10.19%. The WMLP Term Loan is a primary obligation of Oxford Mining Company, LLC, a wholly owned subsidiary of WMLP, is guaranteed by WMLP and its subsidiaries, and is secured by substantially all of WMLP’s and its subsidiaries’ assets.

The WMLP Term Loan also provides for paid in kind interest (“PIK Interest”) at a variable rate between 1.00% and 3.00% based on WMLP’s consolidated net leverage ratio, as defined in the financing agreement. As of December 31, 2017 and 2016, the WMLP Term Loan had a PIK Interest rate of 3.00%. The rate of PIK Interest is determined on a quarterly basis with the PIK Interest added quarterly to the then-outstanding principal amount ~~available for borrowings~~of the WMLP Term Loan. PIK Interest under the ~~credit~~WMLP Term Loan financing agreement ~~can be increased~~was $9.3 million for the year ended December 31, 2017. The outstanding WMLP Term Loan amount as of December 31, 2017 represents the principal balance of $287.3 million, plus PIK Interest of $25.4 million.

The WMLP Term Loan limits cash distributions to ~~$100.0~~the Restricted Distributions, an aggregate amount not to exceed $15.0 million, if WMLP has: (i) a consolidated total net leverage ratio of greater than 3.75, or fixed charge coverage ratio of less than 1.00 (as such ratios are defined in the WMLP Term Loan financing agreement), or (ii) liquidity of less than $7.5 million, after giving effect to such cash distribution and applying WMLP's availability under the WMLP Revolver. As of December 31, 2017, WMLP’s consolidated total net leverage ratio is in excess of 3.75. Further, as of December 31, 2017, WMLP has utilized the full $15.0 million limit on Restricted Distribution payments and is restricted from making any further distributions under the terms of the WMLP Term Loan financing agreement.

The WMLP Term Loan contains customary affirmative covenants, negative covenants, events of default as well as certain ~~circumstances.~~customary cross-default provisions. Our compliance or non-compliance with these covenants is discussed above.

Revolver

Pursuant to the second amended and restated loan and security agreement, dated as of December 16, 2014, by and among the Company and certain of its subsidiaries, lenders party thereto, and Canadian Imperial Bank of Commerce (formerly known as The ~~revolver~~PrivateBank and Trust Company), as administrative agent (the “Revolver”) we have a total aggregate borrowing capacity of $60.0 million between June 15th and August 31st of each year, with an aggregate borrowing capacity of $50.0 million outside of these periods. The availability of the Revolver consists of a $30.0 million sub-facility ($35.0 million with the seasonal increase) available to our U.S. borrowers and a $20.0 million sub-facility ($25.0 million with the seasonal increase)

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONT.)

available to our Canadian borrowers. The Revolver may support an equal amount of letters of credit, ~~which would reduce the balance available~~with outstanding letter of credit balances reducing availability under the ~~revolver. At~~facility. Borrowings under the Revolver initially bear interest either at a rate 0.75% in excess of the base rate or at a rate 2.75% per annum in excess of LIBOR, at our election. An unused line fee of 0.50% per annum is payable monthly on the average unused amount of the Revolver. The Revolver contains various affirmative, negative and financial covenants. Financial covenants in the agreement include certain specified minimum fixed charge coverage ratios. Our compliance or non-compliance with these covenants is discussed above.

Twelfth Amendment to Second Amended and Restated Loan and Security Agreement

On October 30, 2017, we executed an amendment to our existing Revolver with Canadian Imperial Bank of Commerce (formerly known as The PrivateBank and Trust Company), as agent and as a lender, and East West Bank, as a lender ("Twelfth Amendment"). The Twelfth Amendment amended: (a) financial statement reporting to include monthly reconciliations of U.S., Canadian and Consolidated EBITDA to corresponding Net Income figures and a monthly forecast of financial covenants for the next occurring quarter; (b) the calculation under the term “US EBITDA” to remove certain fees paid to legal and financial advisors in connection with the assessment of Westmoreland’s consolidated debt structure; and (c) calculations under the terms “Canadian EBITDA” and “Canadian Fixed Charges” to remove certain financial results attributable to the Coal Valley Mine, as well as permitted netting of certain Returned Collateral against unfinanced Canadian Capital Expenditures, in connection with any sale or discontinuance of operations of the Coal Valley Mine; as such capitalized terms are defined in our Second Amended and Restated Loan and Security Agreement, as amended, governing the Revolver.

Thirteenth Amendment to Second Amended and Restated Loan and Security Agreement

On March 30, 2018, we executed the Thirteenth Amendment to our Revolver with Canadian Imperial Bank of Commerce (formerly known as The PrivateBank and Trust Company), as agent and as lender, and East West Bank, as a lender, which amended, among other things, the calculation of Canadian EBITDA as it is used in the fixed charge coverage ratio. The amendment removed certain financial results attributable to the Coal Valley mine from Canadian EBITDA and results in our compliance with the covenant for the year ended December 31, ~~2014, availability~~2017. Absent this amendment we would have failed the financial covenant. The amendment also waives the requirement that we deliver an unqualified opinion of our independent certified accountants for our audited financial statements for the year ended December 31, 2017 solely due to the receipt of a going concern opinion. This amendment is further described in Item 9B - Other Information of this Annual Report on Form 10-K.

Our revolving credit facilities had the ~~revolver was $16.9 million with an outstanding balance~~following details as of ~~$9.6 million and $23.5 million supporting letters of credit.~~ December 31, 2017 (in millions):



Revolver Details	U.S. Borrowers		Canadian Borrowers		U.S. & Canadian Borrowers
Line of credit maximum availability - without seasonal increase from June 15 to August 31	$	30.0	$	20.0	$	50.0
Letters of credit outstanding	2.4		—		2.4
Borrowing base restrictions	14.4		4.5		18.9
Line of credit draws	—		—		—
Line of credit availability	$	13.2	$	15.5	$	28.7

All extensions of credit under the ~~revolver~~Revolver are collateralized by a first priority security interest in and lien upon the inventory and accounts receivable of substantially all of the ~~Company's~~Company’s subsidiaries (other than Absaloka Coal, LLC, Westmoreland Risk Management, Inc.,Westmoreland Resources GP, LLC, Westmoreland Resource Partners, LP and certain other immaterial subsidiaries). Pursuant to the Intercreditor Agreement, the holders of the 8.75% Notes and the Term Loan have a subordinate lien on these assets. ~~The revolver has a maturity date of December 31, 2018. The Company capitalized debt issuance costs of $0.7 million in 2014 related to the revolver amendments.~~

Borrowings under the Second Amended and Restated Loan Agreement initially bear interest either at a rate 0.75% in excess of the base rate (as detailed in the Second Amended and Restated Loan Agreement) or at a rate 2.75% per annum in excess of LIBOR, at the Borrowers’ election. An unused line fee of 0.50% per annum is payable monthly on the average unused amount of the revolver.WMLP Revolver

The loan agreement contains various affirmative, negative and financial covenants. Financial covenants in the agreement include a fixed charge coverage ratio and an EBITDA measure. The fixed charge coverage ratio must meet or exceed a specified minimum. The EBITDA covenant requires a minimum amount of EBITDA to be achieved. The Company met these covenant requirements as of December 31, 2014.

~~10.75%~~ ~~Senior Notes~~

On ~~February 7, 2014, the Company closed on~~October 23, 2015, WMLP and its subsidiaries entered into a private offering of $425.0 million in aggregate principal amount of 10.75% senior notes due 2018 at a price of 106.875% plus accrued interest from February 1, 2014. The private offering had the same terms as the then existing $251.5 million outstanding 10.75% Senior Notes. Total proceeds of the offering were $454.2 million, which included $29.2 million of debt premium. The net proceeds of the offering of the $425.0 million private offering were used to finance the $282.8 million initial cash payment for the Canadian AcquisitionLoan and ~~cash transaction costs associated~~Security Agreement (the “WMLP Revolver”) with the lenders party thereto and Canadian ~~Acquisition~~Imperial Bank of Commerce (formerly known as The PrivateBank and the private offering of approximately $24.0 million. The remaining balance of the proceeds were used to fund the prepayment of the WML Notes and for other general corporate purposes. The Company recorded $12.5 million of loss on extinguishment of debt for the year ended December 31, 2014 related to the payoff of the WML term debt. This loss included an $11.6 million make-whole payment with the remaining loss due to the write-off of unamortized debt issuance costs. In connection with the WML prepayment, the WML revolving credit facility was terminated.

On December 16, 2014, the Company used the proceeds from the 8.75% Senior Secured Notes and the Term Loan to pay the $675.5 million aggregate outstanding balance of the 10.75% senior notes. In connection with the repayment of the 10.75 Senior Notes, the Company recorded loss on extinguishment of $34.9 million for the year ended December 31, 2014. This loss included an $32.9 million make-whole payment with the remaining loss due to the write-off of unamortized debt issuance costs and unamortized debt premium.

~~WMLP Loan~~

~~On December 31, 2014, WMLP closed on a new credit facility under a financing agreement (the “WMLP Loan”)~~Trust Company). The WMLP Loan consists of a $175.0 million term loan, with an option for an additional $120.0 million in term loans for acquisitions if requested by the WMLP and approved by the issuing lenders. The WMLP Loan matures in December 2018. Borrowings under the WMLP Loan are secured by substantially all of WMLP’s physical assets. Proceeds of the new credit facility were used to retire WMLP’s then existing first and second lien credit facilities and to pay fees and expenses related toRevolver expired on its ~~new credit facility, with the limited amount of remaining proceeds being available as working capital.~~

~~As of~~ December 31, ~~2014, the $175.0 million outstanding under the WMLP Loan bears interest at a variable rate per annum equal to, at the WMLP’s option, the LIBOR (as defined~~2017 maturity date and was not replaced or extended by WMLP.

Capital Lease Obligations

The Company engages in ~~the WMLP Financing Agreement)(floor of 0.75% plus 8.50%) or the Reference Rate (as defined~~leasing transactions for equipment utilized in ~~the WMLP Financing Agreement). As of~~its mining operations. At December 31, ~~2014, the WMLP Loan had a cash interest rate of 9.25%, consisting of the LIBOR floor (0.75%) plus 8.50%.~~2017

The WMLP Loan also provides for “PIK Interest” (paid-in-kind interest as defined in the WMLP Financing Agreement) at a variable rate per annum between 1.00% and 3.00% based on WMLP’s total net leverage ratio (as defined in the WMLP Financing Agreement). The rate of PIK Interest is recalculated on a quarterly basis with the PIK Interest added quarterly to the then outstanding principal amount of the term loan under the WMLP Loan. PIK Interest under the WMLP Loan was inconsequential for the year ended December 31, 2014.

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As a result of WMLP refinancing the WMLP Loan, the Company recorded a $1.6 million loss on extinguishment of debt in the year ended December 31, 2014 as it pertains to cost associated with repayment of the existing outstanding debt held by WMLP.

~~The WMLP Loan contains customary financial~~ and ~~other covenants. As of December 31, 2014, WMLP was in compliance with all covenants under the terms of the WMLP Loan.~~

~~Capital Leases~~

~~The Company engages in leasing transactions for equipment utilized in its mining operations. At~~ ~~December 31, 2014~~ ~~and~~ ~~2013~~,2016, the capital leases outstanding had a weighted average interest rate of ~~4.66%~~5.20% and ~~6.40%~~4.64%, respectively, and mature at various dates beginning in ~~2015~~2018 through ~~2020.~~2025. During the year ended December 31, ~~2014,~~2017, the Company entered into ~~$15.6~~$1.3 million of new capital leases. ~~In addition, we assumed~~ ~~$122.6 million~~ ~~of capital lease obligations in the Canadian Acquisition.~~


7.	~~POSTRETIREMENT MEDICAL BENEFITS~~

9. POSTRETIREMENT MEDICAL BENEFITS

The Company provides postretirement medical benefits to retired employees and their dependents, mandated by the Coal Industry Retiree Health Act of 1992 and pursuant to collective bargaining agreements. The Company also provides these benefits to qualified full-time employees pursuant to collective bargaining agreements. These benefits are provided through self-insured programs.

The following table sets forth the actuarial present value of postretirement medical benefit obligations and amounts recognized in the Company’s financial statements:


	December 31,
	2014			2013			December 31, 2017			December 31, 2016
	(In thousands)						(In thousands)
Change in benefit obligations:
Net benefit obligation at beginning of year	$	284,329		$	333,842		$	323,601		$	299,373
Liability acquired							—			1,851
Service cost	3,289			4,436			3,018			3,270
Interest cost	12,814			12,139			12,651			12,353
Plan participant contributions	149			132			59			136
Actuarial loss (gain)	19,441			(53,230		)
Actuarial loss							6,893			24,821
Gross benefits paid	(14,860		)	(14,220		)	(15,457		)	(16,914		)
Federal subsidy on benefits paid	1,256			1,230			1,376			1,466
Curtailments							—			(2,755		)
Net benefit obligation at end of year	306,418			284,329			332,141			323,601
Change in plan assets:
Employer contributions	14,711			14,088			15,398			16,778
Plan participant contributions	149			132			59			136
Gross benefits paid	(14,860		)	(14,220		)	(15,457		)	(16,914		)
Fair value of plan assets at end of year	—			—			—			—
Unfunded status at end of year	$	(306,418	)	$	(284,329	)	$	(332,141	)	$	(323,601	)
Amounts recognized in the balance sheet consist of:
Current liabilities	$	(13,263	)	$	(13,955	)	$	(14,734	)	$	(14,892	)
Noncurrent liabilities	(293,156		)	(270,374		)	(317,407		)	(308,709		)
Accumulated other comprehensive loss	39,716			20,292			55,123			51,893
Net amount recognized	$	(266,703	)	$	(264,037	)	$	(277,018	)	$	(271,708	)
Amounts recognized in accumulated other comprehensive loss consists of:
Net actuarial loss	$	44,800		$	26,012		$	58,301		$	55,706
Prior service credit	(5,084		)	(5,720		)	(3,178		)	(3,813		)
	$	39,716		$	20,292		$	55,123		$	51,893

In ~~2014, the Company’s postretirement medical benefit liabilities increased~~ ~~$22.1 million. This increase was primarily driven by a $32.4 million increase due to decreases in discount rates and a $27.0 million increase due to updated mortality~~

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~~NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONT.)~~

~~tables. These increases were partially offset with a $39.9 million decrease in liability primarily due to improved claims experience.~~

~~The Company has elected to amortize its transition obligations over a~~ 20~~-year period.~~ Prior service costs and credits and actuarial gains and losses are amortized over the average life expectancy or average future service of the plan’s participants. ~~The following amounts~~In 2018, $3.9 million will be amortized from accumulated other comprehensive loss into net periodic benefit ~~cost in 2015 (in millions):~~cost.

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Actuarial loss $ 1.9
Prior service credit 0.6

The components of net periodic postretirement medical benefit cost are as follows:


	Years Ended December 31,									Years Ended December 31,
	2014			2013			2012			2017			2016			2015
	(In thousands)									(In thousands)
Components of net periodic benefit cost:
Service cost	$	3,289		$	4,436		$	3,555		$	3,018		$	3,270		$	4,217
Interest cost	12,814			12,139			12,363			12,651			12,353			11,629
Amortization of:
Transition obligation	—			—			93
Prior service credit	(635		)	(636		)	(636		)	(635		)	(636		)	(636		)
Actuarial loss	653			4,641			3,116			4,298			1,895			1,944
Total net periodic benefit cost	$	16,121		$	20,580		$	18,491		$	19,332		$	16,882		$	17,154

The following table shows the net periodic postretirement medical benefit costs that relate to current and former mining operations:


	Years Ended December 31,						Years Ended December 31,
	2014		2013		2012		2017		2016		2015
	(In thousands)						(In thousands)
Former mining operations	$	9,614	$	12,475	$	11,314	$	9,222	$	8,540	$	8,137
Current operations	6,507		8,105		7,177		10,110		8,342		9,017
Total net periodic benefit cost	$	16,121	$	20,580	$	18,491	$	19,332	$	16,882	$	17,154

The costs for the former mining operations are included in Heritage health benefit expenses in the Consolidated Statements of Operations and the costs for current operations are included as operating expenses.

Assumptions

The weighted-average assumptions used to determine the benefit obligations as of the end of each year were as follows:

December 31,
2014 2013
Discount rate 3.75% - 4.25% 4.50% - 5.05%
Measurement date December 31, 2014 December 31, 2013



	December 31, 2017	December 31, 2016
Discount rate	3.45% - 3.85%	3.90% - 4.45%
Measurement date	December 31, 2017	December 31, 2016

Annually, Westmoreland determines discount rates for its retirement benefit plans using our third party actuary’s yield curve which is based on high quality U.S. corporate bonds. The discount rate is ~~adjusted annually based on an Aa corporate bond index adjusted for~~calculated as the ~~difference in~~single effective rate that produces the ~~duration of~~equivalent benefit obligation as that determined when discounting future liability cash flows using spot rates from the ~~bond index and the duration of the benefit obligations. This rate is calculated using a~~ yield ~~curve, which is developed using the average yield for bonds in the tenth to ninetieth percentiles, which excludes bonds with outlier yields.~~curve.

The weighted-average assumptions used to determine net periodic benefit cost were as follows:

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~~NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONT.)~~

December 31,
2014 2013 2012
Discount rate 4.50% - 5.05% 3.60% - 4.15% 4.10%
Measurement date December 31, 2013 December 31, 2012 December 31, 2011



	December 31, 2017	December 31, 2016	December 31, 2015
Discount rate	3.90% - 4.45%	4.10% - 4.65%	3.75% - 4.25%
Measurement date	December 31, 2016	December 31, 2015	December 31, 2014

The following presents information about the assumed health care trend rate:


	December 31,
	2014		2013		December 31, 2017	December 31, 2016
Health care cost trend rate assumed for next year	6.50	%	6.75	%	6.50%	6.75%
Rate to which the cost trend is assumed to decline (ultimate trend rate)	5.00	%	5.00	%	4.75%	4.75%
Year that the trend rate reaches the ultimate trend rate	2021		2021		2025	2025

The effect of a one percent change on the health care cost trend rate used to calculate periodic postretirement medical benefit costs and the related benefit obligation are summarized in the table below:

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	Postretirement Medical Benefits					Postretirement Medical Benefits
	1 % Increase		1 % Decrease			1 % Increase		1 % Decrease
	(In thousands)					(In thousands)
Effect on service and interest cost components	$	2,614	$	(2,096	)	$	2,743	$	(2,125	)
Effect on postretirement medical benefit obligation	$	46,056	$	(37,003	)	48,294		(39,005		)

Cash Flows

The following benefit payments and Medicare D subsidy (which the Company receives as a benefit partially offsetting its prescription drug costs for retirees and their dependents) are expected by the Company:

Postretirement
Medical Benefits

Medicare D
Subsidy

Net
Postretirement
Medical Benefits
(In thousands)
2015 $ 13,263
$ (1,239 ) $ 12,024
2016 13,572
(1,284 ) 12,288
2017 13,889
(1,340 ) 12,549
2018 14,299
(1,390 ) 12,909
2019 14,663
(1,434 ) 13,229
Years 2020 - 2024 76,900
(7,782 ) 69,118



	Postretirement Medical Benefits		Medicare D Subsidy			Net Postretirement Medical Benefits
	(In thousands)
2018	$	16,368	$	(1,634	)	$	14,734
2019	16,889		(1,694		)	15,195
2020	17,399		(1,751		)	15,648
2021	17,802		(1,807		)	15,995
2022	18,261		(1,860		)	16,401
Years 2023 - 2027	94,618		(9,702		)	84,916

Combined Benefit Fund

~~Additionally, the Company makes payments to the UMWA~~The Combined Benefit Fund ~~or CBF, which~~("CBF") is a ~~multiemployer~~multi-employer health plan neither controlled by nor administered by the Company. The CBF is designed to pay health care benefits to UMWA workers (and dependents) who retired prior to 1976. The Company is required by the Coal Act to make monthly premium payments into the CBF. These payments are based on the number of the Company’s UMWA employees who retired prior to 1976, and the Company’s pro-rata assigned share of UMWA retirees whose companies are no longer in business. Contributions to the CBF have decreased over the past three years due to a declining population. The Company expenses payments to the CBF when they are due. The following payments were made to the CBF (in ~~millions)~~thousands):

2014 $ 2.0
2013 2.2
2012 2.3



2017	$	1,445
2016	1,594
2015	1,794

Workers’ Compensation Benefits

~~106~~

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~~NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONT.)~~

The Company was self-insured for workers’ compensation benefits prior to January 1, 1996. Since 1996, the Company has purchased third-party insurance for workers’ compensation claims.

The following table shows the changes in the Company’s workers’ compensation obligation:


	December 31,
	2014			2013			December 31, 2017			December 31, 2016
	(In thousands)
Workers’ compensation, beginning of year (including current portion)	$	7,461		$	9,530		$	5,040		$	5,658
Accretion	200			166			167			115
Claims paid	(405		)	(581		)	(512		)	(399		)
Actuarial changes	(270		)	(1,654		)	(426		)	(334		)
Workers’ compensation, end of year	6,986			7,461			4,269			5,040
Less current portion	(671		)	(717		)
Workers’ compensation, less current portion	$	6,315		$	6,744
Less current portion, included in Other current liabilities							(489		)	(541		)
Workers’ compensation, less current portion, included in Other liabilities							$	3,780		$	4,499

~~The discount rates used in determining the workers’ compensation benefit accruals are adjusted annually based on~~ ~~ten-year Treasury bond rates. At~~ ~~December 31, 2014~~ ~~and~~ ~~2013, the rates were 2.0% and 3.0%, respectively.~~

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Black Lung Benefits

The Company is self-insured for federal and state black lung benefits for former heritage ~~employees~~employees. As of December 31, 2017 and ~~has established an independent trust to pay these benefits.~~

~~The following table sets forth the funded status of~~2016, the Company’s black lung ~~obligation:~~benefit obligations were $18.2 million and $17.6 million, respectively.

December 31,
2014 2013
(In thousands)
Actuarial present value of benefit obligation:
Expected claims from terminated employees $ 953
$ 876
Amounts owed to existing claimants 13,054
13,267
Total present value of benefit obligation 14,007
14,143
Plan assets at fair value, primarily government-backed securities 2,755
5,468
Excess of the black lung benefit obligation over trust assets $ 11,252
$ 8,675

The discount rates used in determining the actuarial present value of the black lung benefit obligation are based on corporate bond yields and are adjusted annually. AtAs of December 31, ~~2014~~2017 and ~~2013~~2016, the rates used were ~~3.40%~~3.37% and ~~4.00%~~3.70%, respectively.

~~Plan Assets~~

~~The fair value of the Company’s Black Lung trust assets by asset category is as follows:~~

December 31, 2014

Quoted Prices
in Active
Markets for
Identical Assets

Significant
Other
Observable
Inputs
Fair Value Level 1 Level 2
(In thousands)
U.S. treasury securities $ 2,615
$ 2,615
$ —
Cash and cash equivalents 140
140
—
$ 2,755
$ 2,755
$ —

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~~WESTMORELAND COAL COMPANY~~10. PENSION AND ~~SUBSIDIARIES~~OTHER SAVING PLANS

~~NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONT.)~~

December 31, 2013

Quoted Prices
in Active
Markets for
Identical Assets

Significant
Other
Observable
Inputs
Fair Value Level 1 Level 2
(In thousands)
U.S. treasury securities $ 5,280
$ 5,280
$ —
Mortgage-backed securities 185
—
185
Cash and cash equivalents 3
3
—
$ 5,468
$ 5,283
$ 185

~~The Black Lung Level 1 trust assets include cash and cash equivalents and U.S. treasury securities.~~

The Black Lung Level 2 trust assets include mortgage-backed securities which are valued via model using various inputs such as daily cash flow, snapshots of US Treasury market, floating rate indices as a benchmark yield, spread over index, periodic and life caps, next coupon adjustment date, and convertibility of the bond.


8.	~~PENSION AND OTHER SAVING PLANS~~

Defined Benefit Pension Plans

The Company provides defined benefit pension plans to qualified full-time employees pursuant to collective bargaining agreements. Benefits are generally based on years of service and the employee’s average annual compensation for the highest five continuous years of employment as specified in the plan agreement. The Company’s funding policy is to contribute annually the minimum amount prescribed, as specified by applicable regulations. The Company may make additional discretionary contributions. In 2009, the Company froze its pension plan for non-represented employees.

~~Supplemental Executive Retirement Plan~~Reclamation Deposits

Certain of the Company’s customers have pre-funded a portion of expected reclamation costs. Amounts received from customers and held on deposit are recorded within Restricted investments, reclamation deposits and bond collateral.

Financial Instruments

Fair Value

Fair value is the price that would be received to sell an asset or paid to transfer a liability in an orderly transaction between market participants at a given measurement date. Valuation techniques used must maximize the use of observable inputs and minimize the use of unobservable inputs. The fair value hierarchy prioritizes the inputs to valuation techniques used to measure fair value. The hierarchy, as defined below, gives the highest priority to unadjusted quoted prices in active markets for identical assets or liabilities and the lowest priority to unobservable inputs.

Level 3, defined as unobservable inputs in which little or no market data exists, therefore requiring an entity to develop its own assumptions.

See Note 4 - Loss On Impairment, Note 6 - Restricted Investments, Reclamation Deposits And Bond Collateral and Note 13 - Fair Value Measurements to the consolidated financial statements for further disclosures related to the Company's fair value estimates.

Intangible Assets and Liabilities

Identifiable intangible assets or liabilities acquired in a business combination are specifically identified and recognized on a standalone basis. These intangible assets and liabilities are amortized on a straight-line basis over the respective useful life of the asset or liability. See Note 7 - Intangible Assets And Liabilities to the consolidated financial statements for further details.

Workers’ Compensation Benefits

The Company ~~maintains a Supplemental Executive Retirement Plan or SERP~~is self-insured for ~~former executives as a result~~workers’ compensation claims incurred prior to 1996. The liabilities for workers’ compensation claims are actuarially determined estimates of ~~employment or severance agreements. The SERP is an unfunded non-qualified deferred compensation plan, which provides benefits~~the ultimate losses incurred based on the Company’s experience. Adjustments to ~~certain employees beyond~~ the ~~maximum limits imposed by~~actuarially determined liability are made annually based on subsequent developments and experience and are included in operations at the ~~Employee Retirement Income Security Act and~~time of the ~~Internal Revenue Code.~~revised estimate. The Company ~~does not expect to add new participants to~~insures its ~~SERP plan.~~current employees through third-party insurance providers and state arrangements.

~~108~~83

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Pneumoconiosis (Black Lung) Benefits

The ~~following table provides a reconciliation~~Company is self-insured for federal and state black lung benefits for former Heritage employees. The Company accounts for these benefits on the accrual basis. An independent actuary annually calculates the present value of the ~~changes~~accumulated black lung obligation. The liability is included in Other liabilities on the ~~benefit obligations~~Consolidated Balance Sheets.

Postretirement Health Care Benefits

The Company accrues the cost to provide the benefits over the employees’ period of active service for postretirement benefits other than pensions. These costs are determined on an actuarial basis. The Company’s Consolidated Balance Sheets reflect the unfunded status of postretirement benefit obligations.

Pension and SERP Plans

The Company accrues the cost to provide the benefits over the employees’ period of active service for the non-contributory defined benefit pension and SERP plans ~~and~~it sponsors. These costs are determined on an actuarial basis. The Company’s Consolidated Balance Sheets reflect the ~~fair value~~unfunded status of ~~assets of the qualified plans and the amounts recognized in the Company’s financial statements for both~~ the defined benefit pension and SERP ~~plans:~~plans, with the current portion of the liability in Other current liabilities.

Deferred Revenue

Defined Benefit Pension
December 31,

SERP
December 31,
2014 2013 2014 2013
(In thousands)
Change in benefit obligation:
Net benefit obligation at beginning of year $ 155,075
$ 172,289
$ 3,640
$ 4,241
Liability acquired 36,087
—
—
—
Service cost 2,425
2,346
—
—
Interest cost 7,963
6,209
168
152
Actuarial loss (gain) 32,505
(18,972 ) 704
(359 )
Benefits and expenses paid (15,119 ) (6,797 ) (383 ) (394 )
Settlements and curtailments (10,862 ) —
—
—
Plan amendments 207
—
—
—
Foreign currency exchange rate changes (1,315 ) —
—
—
Net benefit obligation at end of year 206,966
155,075
4,129
3,640
Change in plan assets:
Fair value of plan assets at the beginning of year 134,149
121,887
—
—
Assets acquired 36,616
—
—
—
Actual return on plan assets 14,392
18,414
—
—
Employer contributions 4,812
645
383
394
Benefits and expenses paid (15,119 ) (6,797 ) (383 ) (394 )
Settlements (12,795 ) —
—
—
Foreign currency exchange rate changes (1,108 ) —
—
—
Fair value of plan assets at end of year 160,947
134,149
—
—
Unfunded status at end of year $ (46,019 ) $ (20,926 ) $ (4,129 ) $ (3,640 )
Amounts recognized in the accompanying balance sheet consist of:
Current liability $ —
$ —
$ (368 ) $ (390 )
Noncurrent liability (46,019 ) (20,926 ) (3,760 ) (3,250 )
Accumulated other comprehensive loss 34,249
11,045
1,815
1,209
Net amount recognized at end of year $ (11,770 ) $ (9,881 ) $ (2,313 ) $ (2,431 )
Amounts recognized in accumulated other comprehensive loss consist of:
Net actuarial loss $ 34,164
$ 11,045
$ 1,815
$ 1,209
Prior service cost 85
—
—
—
$ 34,249
$ 11,045
$ 1,815
$ 1,209
Deferred revenues represent funding received in advance of meeting the revenue recognition criteria. Deferred revenues will be recognized as revenue in the periods in which all revenue recognition criteria have been met.

~~The accumulated benefit obligation for all plans was~~ ~~$211.1 million~~ ~~and~~ ~~$158.7 million~~ at ~~December 31, 2014~~ ~~and~~ ~~2013, respectively.~~ Asset Retirement Obligations

The Company’s ~~pension~~asset retirement obligation, or "ARO," primarily consist of estimated costs to reclaim surface land and ~~SERP liabilities increased~~ ~~$25.6 million~~support facilities at its mines and power plants in ~~2014~~ ~~primarily from decreases in discount rates, updated mortality tables,~~accordance with federal and state reclamation laws as established by each mining permit.

The Company estimates its ARO for final reclamation and mine closure based upon detailed engineering calculations of the amount and timing of the future costs for a third party to perform the required work. These estimates are based on projected pit configurations and are escalated for inflation, and then discounted at a credit-adjusted risk-free rate. The Company records asset retirement cost associated with the initial recorded liability. Asset retirement cost is amortized based on the units of production method over the estimated proven and probable reserves at the related mine, and the ~~Canadian Acquisition.~~

~~Prior service~~ARO is accreted to the projected settlement date. Changes in estimates could occur due to revisions of mine plans, changes in estimated costs ~~and actuarial gains and losses are amortized over the expected future period of service~~or changes in timing of the ~~plan’s participants.~~ performance of reclamation activities.

Income Taxes

The ~~following amounts~~Company is subject to income taxes in the U.S. (including federal and state) and certain foreign jurisdictions. Deferred income taxes are provided for temporary differences arising from differences between the financial statement amount and tax basis of assets and liabilities existing at each balance sheet date using enacted tax rates anticipated to be in effect when the related taxes are expected to be paid or recovered. A valuation allowance is established if it is more likely than not (greater than 50%) that a deferred tax asset will not be realized. In determining the need for a valuation allowance at each reporting period, the Company considers projected realization of tax benefits based on expected levels of future taxable income, the duration of statutory carryforward periods, experience with operating loss and tax credit carryforwards not expiring and availability of tax planning strategies.

Accounting guidance prescribes a recognition threshold and measurement attribute for the financial statement recognition and measurement of a tax position taken or expected to be taken in a tax return. Under this guidance, a company can recognize the benefit of an income tax position only if it is more likely than not (greater than 50%) that the tax position will be ~~amortized from accumulated other comprehensive loss into net periodic benefit cost~~sustained upon tax examination, based solely on the technical merits of the tax position. Guidance is also provided on derecognition, classification, interest and penalties, accounting in ~~2015~~ ~~(in millions):~~interim periods, disclosure and transition.

The Company includes interest and penalties related to income tax matters in income tax expense. Deferred tax liabilities and assets are classified as noncurrent in the Consolidated Balance Sheets.

Pension SERP
Net actuarial loss $ 3.7
$ 0.1

~~109~~84

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The tax effect of pretax income or loss from continuing operations is generally determined by a computation that does not consider the tax effects of items that are not included in continuing operations. The exception to that incremental approach is that all items (for example, items recorded in other comprehensive income) be considered in determining the amount of tax benefit that results from a loss from continuing operations and that shall be allocated to continuing operations.

Deferred Financing Costs

The Company capitalizes costs incurred in connection with establishment of credit facilities and issuance of debt securities. These costs are amortized as an adjustment to interest expense over the life of the debt security or term of the credit facility using the effective interest method. These amounts are recorded in the Consolidated Balance Sheets in Other assets in the case of credit facilities and in the case of debt securities in Long-term debt, less current installments as a direct deduction of the carrying amount of the debt security, consistent with debt discounts in the Consolidated Balance Sheets.

Revenue Recognition

Coal Revenues

The Company generally recognizes revenue from the sale of coal at the time title passes to the customer in accordance with the terms of the underlying sales agreement. The point that title passes varies by agreement. Under our sales agreements, title transfer points include upon loading to truck or rail, upon delivery by truck or rail, upon loading to conveyor belt, upon delivery from conveyor belt and upon delivery to stockpile. Coal revenue is recognized based on the pricing contained in the contracts in place at the time that title passes. Certain of our coal contracts require that the customer reimburse us for reclamation expenditures when incurred. On the delivery of coal these reimbursements are generally not yet fixed or determinable. Accordingly, these reimbursements are not recognized as revenue until they become fixed or determinable, which generally occurs when reclamation expenditures are incurred. Reclamation expenditures may be incurred and the associated revenue related to reimbursements may be recognized during periods of coal delivery, or in some instances, may continue to be incurred and recognized for several years after coal deliveries have been completed.

Power Revenues

ROVA supplied power it produced and generated revenues from such deliveries, as well as through the settlement of related purchased power arrangements. A portion of the payment under the power sales agreement was considered to be an operating lease. The Company recognized amounts previously invoiced as revenue on a straight-line basis over the remaining term of the power sales agreement.

Other Operating Loss (Income)

Other operating loss (income) in the Consolidated Statements of Operations reflects items of income or loss from sources other than coal or power revenues. The Company recognizes other operating income when business interruption losses have been incurred and reimbursement is realized or realizable. Insurance proceeds are included in Net cash provided by operating activities when received.

Share-Based Compensation

Share-based compensation expense is generally measured at the grant date and recognized as expense over the vesting period of the entire award for stock-settled grants and remeasured at fair value at the end of each period and accrued as a liability for cash-settled grants. These costs are recorded in Selling and administrative in the Consolidated Statements of Operations. See Note 14 - Share-Based Compensation to the consolidated financial statements for further details.

Derivatives

The Company enters into financial derivatives to manage exposure to fluctuations in power prices. The Company does not utilize derivative financial instruments for trading purposes or for speculative purposes. The Company’s derivative instruments are recorded at fair value with changes in fair value recognized in the Consolidated Statements of Operations at the end of each period in Derivative (gain) loss.

Foreign Exchange Transactions

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Amounts held and transactions denominated in foreign currencies other than the operating unit’s functional currency give rise to foreign exchange gains and losses which are included within (Loss) gain on foreign exchange in the Consolidated Statements of Operations.

Foreign Currency Translation

The functional currency of the Company’s Canadian operations is the Canadian dollar. The Company’s Canadian operations’ assets and liabilities are translated at period end exchange rates, and revenues and costs are translated using average exchange rates for the period. Foreign currency translation adjustments are reported in Other comprehensive loss, net of income taxes in the Consolidated Statements of Comprehensive Loss.

Reclassifications

Certain amounts in prior periods have been reclassified to conform with current year presentation, with no effect on previously reported net loss, cash flows or shareholders’ deficit.

Recently Adopted Accounting Pronouncements

In October 2016, the Financial Accounting Standards Board ("FASB") issued Accounting Standards Update (“ASU") 2016-16, Income Taxes (Topic 740): Intra-Entity Transfers of Assets Other than Inventory, which eliminates the exception that prohibits the recognition of current and deferred income tax effects for intra-entity transfers of assets other than inventory until the asset has been sold to an outside party. The new guidance is effective for fiscal years beginning after December 15, 2017, including interim periods within those fiscal years, with early adoption permitted. The amendments in this update should be applied on a modified retrospective basis through a cumulative-effect adjustment directly to accumulated deficit as of the beginning of the period of adoption. The Company early adopted this standard during the first quarter of 2017, which resulted in a cumulative effect adjustment as of January 1, 2017 reducing Other assets and Accumulated deficit by $0.4 million.

Accounting Pronouncements Effective in the Future

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in the first quarter of 2018 and the adoption of this guidance will not have a material impact on the consolidated financial statements.

In May 2014, the FASB issued ASU 2014-09, Revenue from Contracts with Customers (Topic 606), which supersedes all previously existing revenue recognition guidance. Under this guidance, an entity should recognize revenue when it transfers promised goods or services to customers in an amount that reflects the consideration to which the entity expects to be entitled in exchange for those goods or services. ASU 2015-14, Revenue from Contracts with Customers (Topic 606): Deferral of the Effective Date, issued in August 2015, deferred the effective date of ASU 2014-09 to the first quarter of 2018, with early adoption permitted in the first quarter of 2017.

In March, April, May, and December 2016, the FASB issued the following updates, respectively, to provide supplemental adoption guidance and clarification to ASU 2014-09. These standards must be adopted concurrently upon the adoption of ASU 2014-09. We are currently evaluating the potential effects of adopting the provisions of these updates.

ASU 2016-08, Revenue from Contracts with Customers: Principal versus Agent Considerations (Reporting Revenue Gross versus Net);

ASU 2016-10, Revenue from Contracts with Customers: Identifying Performance Obligations and Licensing;

ASU 2016-12, Revenue from Contracts with Customers: Narrow-Scope Improvements and Practical Expedients; and

ASU 2016-19, Technical Corrections and Improvements

During 2016, the Company established an implementation team to develop a multi-phase plan to assess the Company’s business and contracts, as well as any changes to processes or systems to adopt the requirements of the new standard. As of the date of this filing, the Company has substantially completed its evaluation of the impact of the new standard under the full retrospective approach. This process included a review of all material contracts, application of the new guidance to each contract, and documentation of related conclusions. Based on our implementation team’s analyses, we have determined that the implementation of the new standard will have a material impact on our consolidated financial statements for long-term coal supply agreements in which we are entitled to payments from customers to reimburse our costs incurred during final reclamation as these payments relate to the only performance obligations within the contract, which consist of the sale of each ton of coal. As these estimates include significant uncertainty, we are still evaluating all assumptions used in the estimate and finalizing the amounts of accelerated revenues we will recognize for the years ended December 31, 2017 and 2016, and as of the transition date of January 1, 2016. The transition date adjustment will be made directly to accumulated deficit as of January 1, 2016, while the transition adjustments for the years ended December 31, 2017 and 2016 will restate previously reported revenues for those periods. These amounts will create a contract asset on our Consolidated Balance Sheets in the form of accounts receivable for final reclamation. Additionally, we are in the process of evaluating disclosure requirements, finalizing accounting policies and implementing changes to the relevant business processes and the control activities required to implement this standard.

2. ACQUISITIONS

Acquisition of San Juan

WSJ financed the San Juan Acquisition principally with a $125.0 million loan from NM Capital Utility Corporation (the “San Juan Loan”), an affiliate of Public Service Company of New Mexico (one of the owners of SJGS). The loan is structured as a senior secured term loan (the “San Juan Loan”) maturing February 1, 2021 and is expected to bear interest at a (i) 7.25% rate (the “Margin Rate”) plus (ii) (A) the London Interbank Offered Rate for a three month period plus (B) a statutory

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reserve rate, which such Margin Rate increases incrementally during each year of the San Juan Loan term with a final Margin Rate of 14.25% in the final year of the term. The San Juan Loan has no prepayment penalties. The agreements governing the San Juan Loan include representations and warranties and covenants regarding the ownership and operation of SJCC and the properties acquired in the Acquisition and standard special purpose bankruptcy remote entity covenants designed to preserve the separateness from Westmoreland of each of (i) WSJ, (ii) WSJ's direct parent company, Westmoreland San Juan Holdings, Inc., and (iii) the San Juan Entities ((i), (ii) and (iii) collectively, the “Westmoreland San Juan Entities”). Obligations under the San Juan Loan are recourse only to the Westmoreland San Juan Entities and their assets, and neither Westmoreland nor its subsidiaries (other than the Westmoreland San Juan Entities) is an obligor under the San Juan Loan in any respect. The agreement governing the San Juan Loan requires that all revenues of the San Juan Entities, aside from payments on certain leases, are deposited into a cash management collection account swept monthly for operating expenses, capital expenditures, and San Juan Loan payment and prepayment.

In connection with certain mining permits relating to the operation of the San Juan mine, WSJ has posted reclamation bonds of $125.2 million with the New Mexico Mining and Minerals Division.

The San Juan Acquisition has been accounted for under the acquisition method of accounting that requires the total purchase consideration to be allocated to the assets acquired and liabilities assumed based on estimates of fair value. Purchase price accounting was considered final as of December 31, 2016. The allocation of the purchase consideration follows (in millions):



	Final as of December 31, 2016
Purchase price:
Cash paid	$	121.0

Allocation of purchase price:
Assets:
Inventories	8.8
Total current assets	8.8
Land and mineral rights	143.9
Plant and equipment	74.6
Other assets	1.3
Total assets	228.6
Liabilities:
Trade payables and other accrued liabilities	13.4
Production taxes	2.0
Asset retirement obligations	0.7
Total current liabilities	16.1
Asset retirement obligations, less current portion	43.5
Postretirement medical benefits	1.9
Deferred income taxes	46.1
Total liabilities	107.6
Net fair value	$	121.0

Unaudited Pro Forma Information

The following unaudited pro forma information has been prepared for illustrative purposes only and assumes the San Juan Acquisition occurred on January 1, 2015. The unaudited pro forma results have been prepared based on estimates and assumptions, which the Company believes are reasonable, however, they are not necessarily indicative of the Consolidated Statements of Operations had the acquisitions occurred on the dates indicated above, or of future results of operations. Due to the full year of ownership in 2017, no pro forma information has been presented below for the year ended December 31, 2017.

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	Years Ended December 31,
	2016			2015
	(In thousands, except per share data)
Total revenues
As reported	$	1,477,960		$	1,419,518
Pro forma (unaudited)	1,504,235			1,714,043

Operating income (loss)
As reported	$	38,130		$	(145,696	)
Pro forma (unaudited)	39,225			(106,606		)

Net loss applicable to common shareholders
As reported	$	(27,101	)	$	(213,645	)
Pro forma (unaudited)	(26,676		)	(187,139		)

Net loss per share applicable to common shareholders, basic & diluted
As reported	$	(1.47	)	$	(11.93	)
Pro forma (unaudited)	(1.44		)	(10.45		)

Kemmerer Drop

On August 1, 2015, we contributed 100% of the outstanding equity interests in Westmoreland Kemmerer, LLC (“Kemmerer”) to WMLP in exchange for $230 million in aggregate consideration, comprised of $115 million in cash and $115 million in newly issued WMLP Series A Convertible Units (the “Series A Units” and such transaction, the “Kemmerer Drop”). In connection with the Kemmerer Drop, all employees of Kemmerer and related employee liabilities, including but not limited to postretirement pension obligations and postretirement health benefits, were transferred to the Parent. The Series A Units are convertible into common units representing limited partner interests of WMLP (“Common Units”), on a one-for-one basis, upon the earlier of (i) the date on which WMLP first makes a regular quarterly cash distribution to holders of Common Units in an amount equal to at least $0.22 per Common Unit, or (ii) a change of control of WMLP. Following the Kemmerer Drop, at December 31, 2017 we held an approximately 93.94% controlling interest in WMLP (on a fully diluted basis). The Kemmerer Drop represents a reorganization of entities under common control. Accordingly, the net assets transferred are deemed to have transferred at the $102.6 million carrying value as of the date of transfer. No gain or loss was recognized.

3. VARIABLE INTEREST ENTITY

As of December 31, 2017, the Company consolidated its 100% owned WSJ subsidiary which is a variable interest entity (“VIE”). WSJ’s classification as a VIE is due to another party having the potential right to receive WSJ’s residual returns. The Company is the primary beneficiary because it has the power to direct the activities that most significantly impact WSJ’s economic performance. Accordingly, the Company consolidated the operating results, assets and liabilities of WSJ. See Note 2 - Acquisitions and Note 8 - Debt And Lines Of Credit to the consolidated financial statements.

The following table presents the carrying amounts, after eliminating the effect of intercompany transactions, included in the Consolidated Balance Sheets that are for the use of or are the obligation of WSJ (in thousands):



	December 31, 2017		December 31, 2016
Assets	$	203,737	$	268,910
Liabilities	167,529		243,884
Net carrying amount	$	36,208	$	25,026

4. LOSS ON IMPAIRMENT

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.

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5. INVENTORIES

Inventories consisted of the following:



	December 31, 2017			December 31, 2016
	(In thousands)
Coal stockpiles	$	38,145		$	44,692
Materials and supplies	73,517			84,444
Reserve for obsolete inventory	(4,867		)	(3,621		)
Total	$	106,795		$	125,515

6. RESTRICTED INVESTMENTS, RECLAMATION DEPOSITS AND BOND COLLATERAL

Coal segments maintain government-required bond collateral that assures compliance with applicable federal and state regulations relating to the performance of final reclamation activities. The amounts deposited in the bond collateral account secure the bonds issued by the bonding company. The Corporate segment is required to obtain surety bonds in connection with its self-insured workers’ compensation plan and certain health care plans. The Company’s surety bond underwriters require collateral to issue these bonds. Prior to December 31, 2017, the Power segment was required to maintain a collateral account related to its contracts to purchase power.

The Company invests certain bond collateral, reclamation deposits and other restricted investments in a limited selection of fixed-income investment options and receives the corresponding investment returns. These investments are not available to meet the Company’s general cash needs. These investments include available-for-sale securities, which are reported at fair value with unrealized gains and losses excluded from earnings and reported in Accumulated other comprehensive loss in the Consolidated Balance Sheets. On disposal, the resulting gain or loss is reported in Other (loss) income in the Consolidated Statements of Operations.

The Company’s carrying value and estimated fair value of Restricted investments, reclamation deposits and bond collateral as of December 31, 2017 were as follows:



	Restricted Investments and Bond Collateral		Reclamation Deposits		Total Restricted Investments, Reclamation Deposits and Bond Collateral
	(In thousands)
Cash and cash equivalents	$	42,549	$	6,643	$	49,192
Time deposits	2,467		—		2,467
Available-for-sale	78,157		70,378		148,535
	$	123,173	$	77,021	$	200,194

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WESTMORELAND COAL COMPANY AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONT.)

The Company’s carrying value and estimated fair value of its Restricted investments, reclamation deposits and bond collateral as of December 31, 2016 were as follows:



	Restricted Investments and Bond Collateral		Reclamation Deposits		Total Restricted Investments, Reclamation Deposits and Bond Collateral
	(In thousands)
Cash and cash equivalents	$	66,860	$	2,673	$	69,533
Time deposits	2,473		—		2,473
Available-for-sale	75,580		71,689		147,269
	$	144,913	$	74,362	$	219,275

Available-for-Sale Restricted Investments

The cost basis, gross unrealized holding gains and losses, and fair value of available-for-sale securities as of December 31, 2017 were as follows:



	Restricted Investments and Bond Collateral			Reclamation Deposits			Total Restricted Investments, Reclamation Deposits and Bond Collateral
	(In thousands)
Cost basis	$	78,564		$	70,576		$	149,140
Gross unrealized holding gains	521			617			1,138
Gross unrealized holding losses	(928		)	(815		)	(1,743		)
Fair value	$	78,157		$	70,378		$	148,535

The cost basis, gross unrealized holding gains and losses, and fair value of available-for-sale securities as of December 31, 2016 were as follows:



	Restricted Investments and Bond Collateral			Reclamation Deposits			Total Restricted Investments, Reclamation Deposits and Bond Collateral
	(In thousands)
Cost basis	$	76,558		$	72,381		$	148,939
Gross unrealized holding gains	251			453			704
Gross unrealized holding losses	(1,229		)	(1,145		)	(2,374		)
Fair value	$	75,580		$	71,689		$	147,269

Maturities of available-for-sale securities were as follows as of December 31, 2017:



	Cost Basis		Fair Value
	(In thousands)
Due within one year	$	13,960	$	13,423
Due in five years or less	60,827		60,447
Due after five years to ten years	32,381		32,527
Due in more than ten years	41,972		42,138
	$	149,140	$	148,535

For the years ended December 31, 2017, 2016, and 2015, the Company recorded realized (losses) gains of $(0.3) million, $0.2 million, and $0.1 million, respectively, on the sale of available-for-sale securities.

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7. INTANGIBLE ASSETS AND LIABILITIES

Identifiable intangible assets acquired in a business combination are specifically identified and recognized on a standalone basis. Intangible assets result from more favorable contract prices than market prices in lease agreements as measured during a business combination. As a result of prior period acquisitions, we determined that the most significant acquired identifiable intangible assets are related to favorable lease agreements. These intangible assets are recorded in Other assets on our Consolidated Balance Sheets and are amortized on a straight-line basis over the remaining terms of the lease agreements.



	December 31, 2017
	Estimated Remaining Life (years)	Cost		Accumulated Amortization		Net Carrying Value
	(In thousands except for years data)
Favorable lease agreements	12	$	32,174	$	6,327	$	25,847



	December 31, 2016
	Estimated Remaining Life (years)	Cost		Accumulated Amortization		Net Carrying Value
	(In thousands except for years data)
Favorable lease agreements	13	$	32,174	$	4,142	$	28,032



	Amount of Amortization to Recognize in Expense

2018	$	2,184
2019	2,184
2020	2,184
2021	2,184
2022	2,184

8. DEBT AND LINES OF CREDIT

The Company and its subsidiaries are subject to the following debt arrangements:

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONT.)



	Issuance Amount	Issuance Date	Maturity Date	Total Debt Outstanding
	Issuance Amount	Issuance Date	Maturity Date	December 31, 2017			December 31, 2016
	(In millions)	(MM/DD/YY)	(MM/DD/YY)	(In thousands)
8.75% Notes	$350.0	12/16/14	1/1/22	$	350,000		$	350,000
Term Loan	425.0	12/16/14	12/16/20	320,595			323,883
San Juan Loan	125.0	2/1/16	2/1/21	56,640			95,000
WMLP Term Loan	295.0	12/31/14	12/31/18	312,734			306,189
Revolver	*	12/16/14	12/31/18	—			—
Capital lease obligations	Varies	Varies	Varies	33,113			55,061
Other debt	Varies	Varies	Varies	2,826			16,464
Total debt				1,075,908			1,146,597
Less debt discount and issuance costs, net				(27,501		)	(37,531		)
Less current installments, net of debt discount and issuance costs				(983,427		)	(86,272		)
Total non-current debt				$	64,980		$	1,022,794

____________________

* Not applicable.

The following table presents aggregate contractual debt maturities of all long-term debt as of December 31, 2017 (in thousands):



Maturity Date⁽¹⁾	Debt Held by WMLP		All Other Debt		Total Debt Outstanding
2018	$	316,982	$	21,345	$	338,327
2019	4,175		17,263		21,438
2020	1,768		339,548		341,316
2021	1,664		21,165		22,829
2022	1,998		350,000		351,998
Thereafter	—		—		—
Total debt	$	326,587	$	749,321	$	1,075,908

_________________

(1) Debt obligations are scheduled based on their contractual maturities and are not reflective of any potential accelerations discussed further below.

Covenant Compliance

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8.75% Notes

Pursuant to our senior note indenture, dated as of December 16, 2014, by and among the Company, the guarantors named therein, and U.S. Bank National Association, as trustee and notes collateral agent (the “Indenture”), our senior secured 8.75% Notes (“8.75% Notes”) were issued at a 1.292% discount and bear a fixed interest rate of 8.75% payable semiannually, on January 1 and July 1 of each year, commencing July 1, 2015. The 8.75% Notes are a primary obligation of the Company and are guaranteed by Westmoreland Energy LLC, Westmoreland Mining LLC and Westmoreland Resources, Inc. and their respective subsidiaries (other than Absaloka Coal, LLC, Westmoreland Risk Management, Inc. and certain other immaterial subsidiaries), referred to as the “Guarantors.” The 8.75% Notes are not guaranteed by Westmoreland Canada LLC or any of its subsidiaries, Westmoreland San Juan, LLC or any of its subsidiaries, or Westmoreland Resources GP, LLC or WMLP, referred to as the “Non-guarantors.”

The 8.75% Notes are the Company’s senior secured obligations, rank equally in right of payment with all of the Company’s existing and future senior obligations, including the Term Loan (defined below under “Term Loan”) and rank senior to all of the Company’s existing and future indebtedness that is expressly subordinated to the 8.75% Notes. The 8.75% Notes have not been registered under the Securities Act of 1933. The 8.75% Notes contain certain customary cross-default provisions. In 2014, the Company capitalized debt issuance costs of $10.2 million in connection with the 8.75% Notes.

The Company may redeem all or part of the 8.75% Notes beginning on January 1, 2018 at the redemption prices set forth in the 8.75% Notes agreement, and prior to January 1, 2018 at 100% of the principal amount plus the applicable premium described in the 8.75% Notes agreement. In addition, at any time prior to January 1, 2018, the Company may redeem up to 35% of the aggregate principal amount of the 8.75% Notes with the net cash proceeds of certain equity offerings at a redemption price equal to 108.75% of the principal amount to be redeemed, together with accrued and unpaid interest, if any, to the redemption date, subject to certain conditions.

The 8.75% Notes and the guarantees are secured equally and ratably with the Term Loan (i) by first priority liens on substantially all of the Company’s and the guarantor parties’ tangible and intangible assets (excluding certain equity interests, mineral rights and sales contracts and certain assets subject to existing liens) and (ii) subject to the Revolver (as defined below), a second priority lien on substantially all cash, accounts receivable and inventory of the Company and the guarantors, and any other property with respect to, evidencing or relating to such cash, accounts receivable and inventory (whether now owned or hereinafter arising or acquired) and the proceeds and products thereof, subject in each case to permitted liens and certain exclusions (the “Notes Collateral”). The Notes Collateral is shared equally with the lenders under the Term Loan, who hold identical first and second priority liens, as applicable, on the Notes Collateral.

The 8.75% Notes restrict the Company’s and its restricted subsidiaries’ ability to, among other things, (i) incur, assume or guarantee additional indebtedness or issue preferred stock; (ii) declare or pay dividends on, or make other distributions in respect of, their capital stock; (iii) purchase or redeem or otherwise acquire for value any capital stock or subordinated indebtedness; (iv) make investments, other than permitted investments; (v) create certain liens or use assets as security; (vi) enter into agreements restricting the ability of any restricted subsidiary to pay dividends, make loans, or any other distributions to the Company or other restricted subsidiaries; (vii) engage in transactions with affiliates; and (viii) consolidate or merge with or into other companies or transfer all or substantially all of their assets.

The 8.75% Notes contain customary affirmative covenants, negative covenants, events of default, as well as certain customary cross-default provisions. Our compliance or non-compliance with these covenants is discussed above.

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Term Loan

Pursuant to our credit agreement, dated as of December 22, 2014, by and among the Company, the lenders from time to time party thereto, and Bank of Montreal, as administrative agent, as amended (“Term Loan”), the $350.0 million Term Loan was issued at a 2.50% discount and accrues interest on a quarterly basis at a variable interest rate which is set at our election of (i) one-, two-, three- or six-month London Interbank Offered Rate (“LIBOR”) plus 6.50% or (ii) a base rate (determined with reference to the highest of the prime rate, the Federal Funds Rate plus 0.05%, or one-month LIBOR plus 1.00%) plus 5.50%. As of December 31, 2017, the cash interest rate was 8.19%. In 2014, the Company capitalized debt issuance costs of $8.4 million in connection with the Term Loan.

The Term Loan is guaranteed by Westmoreland Energy LLC, Westmoreland Mining LLC, Westmoreland Resources, Inc. and certain other direct and indirect subsidiaries of the Company (other than Absaloka Coal, LLC, Westmoreland Risk Management, Inc., Westmoreland Canada, LLC, Westmoreland Resources GP, LLC, Westmoreland Resource Partners, LP and certain other immaterial subsidiaries). The obligations under the Term Loan are secured by identical first and second priority liens, as applicable, on the Notes Collateral.

Term Loan Add-on

On January 22, 2015, the Company amended the Term Loan to increase the borrowings by $75.0 million, for an aggregate principal amount of $425.0 million as of that date. The amendments to the Term Loan were made in connection with the acquisition of Buckingham Coal Company, LLC. Net proceeds were $71.0 million after a 2.50% discount, 1.50% broker fee, a consent fee of 1.17%, and $0.1 million of additional debt issuance costs. With this addition, the quarterly principal payment due commencing March 31, 2015 is $1.1 million. Under the Term Loan, we are required to offer a portion of our excess cash flows for each fiscal year, beginning with the fiscal year ended December 31, 2015.

In conjunction with the Kemmerer Drop, the Company amended the Term Loan to remove Kemmerer as a guarantor. In addition, $94.1 million of the proceeds received from WMLP related to the Kemmerer Drop were used to pay down the Term Loan.

San Juan Loan

On January 31, 2016, Westmoreland San Juan, LLC (“WSJ”), a special purpose subsidiary of Westmoreland, acquired San Juan Coal Company (“SJCC”), which operates the San Juan mine in Farmington, New Mexico, and San Juan Transportation Company (the “San Juan Acquisition”) for a total cash purchase price of $121.0 million after customary post-closing adjustments. The San Juan mine is the exclusive supplier of coal to the adjacent San Juan Generating Station (“SJGS”) under a coal supply agreement with tonnage and pricing adjusting quarterly through 2022. WSJ financed the San Juan Acquisition in part with a senior secured $125.0 million loan (“San Juan Loan”) pursuant to the loan agreement, dated as of February 1, 2016, by and among WSJ and the remaining Westmoreland San Juan Entities as guarantors, and NM Capital Utility Corporation (an affiliate of Public Service Company of New Mexico, part owner of SJGS) as lender. The San Juan Loan was issued at a 6.70% discount, incurred $3.1 million of debt issuance costs and pays interest and principal on a quarterly basis at an interest rate of (i) the Margin Rate of 7.25% plus (ii) (A) the LIBOR for a three month period plus (B) a statutory reserve rate, which such Margin Rate increases incrementally during each year of the San Juan Loan term with a final Margin Rate of 14.25% in the final year of the term. As of December 31, 2017, the cash interest rate was 10.63%. In addition, in the event the loan is not paid off prior to maturity, the price of the coal in our coal supply agreement decreases by 10% after January 1, 2019 and 15% after January 1, 2021.

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The San Juan Loan contains customary affirmative covenants and negative covenants. Our compliance or non-compliance with these covenants is discussed above.

WMLP Term Loan

Pursuant to the financing agreement, dated as of December 31, 2014, by and among Oxford Mining Company, LLC, WMLP and each of its subsidiaries, lenders from time to time party thereto, and U.S. Bank National Association, as administrative agent, WMLP entered into a term loan (“WMLP Term Loan”) which consists of a $175.0 million, with an option for an additional $120.0 million in term loans for acquisitions, which was exercised on August 1, 2015 to finance the Kemmerer Drop. Proceeds from the credit facility were used to retire WMLP’s previously existing first and second lien credit facilities and to pay fees and expenses related to its existing credit facility, with the remaining proceeds being available as working capital. The WMLP Term Loan was not issued at a discount or a premium and $8.6 million of debt issuance costs were recognized at December 31, 2014. The WMLP Term Loan pays interest on a quarterly basis and bears interest at a variable rate equal to the 3-month LIBOR at each quarter end (1.69% as of December 31, 2017), subject to a floor of 0.75%, plus 8.50% or the Reference Rate, as defined in the financing agreement. As of December 31, 2017, the WMLP Term Loan had a cash interest rate of 10.19%. The WMLP Term Loan is a primary obligation of Oxford Mining Company, LLC, a wholly owned subsidiary of WMLP, is guaranteed by WMLP and its subsidiaries, and is secured by substantially all of WMLP’s and its subsidiaries’ assets.

The WMLP Term Loan also provides for paid in kind interest (“PIK Interest”) at a variable rate between 1.00% and 3.00% based on WMLP’s consolidated net leverage ratio, as defined in the financing agreement. As of December 31, 2017 and 2016, the WMLP Term Loan had a PIK Interest rate of 3.00%. The rate of PIK Interest is determined on a quarterly basis with the PIK Interest added quarterly to the then-outstanding principal amount of the WMLP Term Loan. PIK Interest under the WMLP Term Loan financing agreement was $9.3 million for the year ended December 31, 2017. The outstanding WMLP Term Loan amount as of December 31, 2017 represents the principal balance of $287.3 million, plus PIK Interest of $25.4 million.

The WMLP Term Loan limits cash distributions to the Restricted Distributions, an aggregate amount not to exceed $15.0 million, if WMLP has: (i) a consolidated total net leverage ratio of greater than 3.75, or fixed charge coverage ratio of less than 1.00 (as such ratios are defined in the WMLP Term Loan financing agreement), or (ii) liquidity of less than $7.5 million, after giving effect to such cash distribution and applying WMLP's availability under the WMLP Revolver. As of December 31, 2017, WMLP’s consolidated total net leverage ratio is in excess of 3.75. Further, as of December 31, 2017, WMLP has utilized the full $15.0 million limit on Restricted Distribution payments and is restricted from making any further distributions under the terms of the WMLP Term Loan financing agreement.

The WMLP Term Loan contains customary affirmative covenants, negative covenants, events of default as well as certain customary cross-default provisions. Our compliance or non-compliance with these covenants is discussed above.

Revolver

Pursuant to the second amended and restated loan and security agreement, dated as of December 16, 2014, by and among the Company and certain of its subsidiaries, lenders party thereto, and Canadian Imperial Bank of Commerce (formerly known as The PrivateBank and Trust Company), as administrative agent (the “Revolver”) we have a total aggregate borrowing capacity of $60.0 million between June 15th and August 31st of each year, with an aggregate borrowing capacity of $50.0 million outside of these periods. The availability of the Revolver consists of a $30.0 million sub-facility ($35.0 million with the seasonal increase) available to our U.S. borrowers and a $20.0 million sub-facility ($25.0 million with the seasonal increase)

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONT.)

available to our Canadian borrowers. The Revolver may support an equal amount of letters of credit, with outstanding letter of credit balances reducing availability under the facility. Borrowings under the Revolver initially bear interest either at a rate 0.75% in excess of the base rate or at a rate 2.75% per annum in excess of LIBOR, at our election. An unused line fee of 0.50% per annum is payable monthly on the average unused amount of the Revolver. The Revolver contains various affirmative, negative and financial covenants. Financial covenants in the agreement include certain specified minimum fixed charge coverage ratios. Our compliance or non-compliance with these covenants is discussed above.

Twelfth Amendment to Second Amended and Restated Loan and Security Agreement

Thirteenth Amendment to Second Amended and Restated Loan and Security Agreement

On March 30, 2018, we executed the Thirteenth Amendment to our Revolver with Canadian Imperial Bank of Commerce (formerly known as The PrivateBank and Trust Company), as agent and as lender, and East West Bank, as a lender, which amended, among other things, the calculation of Canadian EBITDA as it is used in the fixed charge coverage ratio. The amendment removed certain financial results attributable to the Coal Valley mine from Canadian EBITDA and results in our compliance with the covenant for the year ended December 31, 2017. Absent this amendment we would have failed the financial covenant. The amendment also waives the requirement that we deliver an unqualified opinion of our independent certified accountants for our audited financial statements for the year ended December 31, 2017 solely due to the receipt of a going concern opinion. This amendment is further described in Item 9B - Other Information of this Annual Report on Form 10-K.

Our revolving credit facilities had the following details as of December 31, 2017 (in millions):



Revolver Details	U.S. Borrowers		Canadian Borrowers		U.S. & Canadian Borrowers
Line of credit maximum availability - without seasonal increase from June 15 to August 31	$	30.0	$	20.0	$	50.0
Letters of credit outstanding	2.4		—		2.4
Borrowing base restrictions	14.4		4.5		18.9
Line of credit draws	—		—		—
Line of credit availability	$	13.2	$	15.5	$	28.7

All extensions of credit under the Revolver are collateralized by a first priority security interest in and lien upon the inventory and accounts receivable of substantially all of the Company’s subsidiaries (other than Absaloka Coal, LLC, Westmoreland Risk Management, Inc.,Westmoreland Resources GP, LLC, Westmoreland Resource Partners, LP and certain other immaterial subsidiaries). Pursuant to the Intercreditor Agreement, the holders of the 8.75% Notes and the Term Loan have a subordinate lien on these assets.

WMLP Revolver

On October 23, 2015, WMLP and its subsidiaries entered into a Loan and Security Agreement (the “WMLP Revolver”) with the lenders party thereto and Canadian Imperial Bank of Commerce (formerly known as The PrivateBank and Trust Company). The WMLP Revolver expired on its December 31, 2017 maturity date and was not replaced or extended by WMLP.

Capital Lease Obligations

The Company engages in leasing transactions for equipment utilized in its mining operations. At December 31, 2017

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONT.)

and 2016, the capital leases outstanding had a weighted average interest rate of 5.20% and 4.64%, respectively, and mature at various dates beginning in 2018 through 2025. During the year ended December 31, 2017, the Company entered into $1.3 million of new capital leases.

9. POSTRETIREMENT MEDICAL BENEFITS

The following table sets forth the actuarial present value of postretirement medical benefit obligations and amounts recognized in the Company’s financial statements:



	December 31, 2017			December 31, 2016
	(In thousands)
Change in benefit obligations:
Net benefit obligation at beginning of year	$	323,601		$	299,373
Liability acquired	—			1,851
Service cost	3,018			3,270
Interest cost	12,651			12,353
Plan participant contributions	59			136
Actuarial loss	6,893			24,821
Gross benefits paid	(15,457		)	(16,914		)
Federal subsidy on benefits paid	1,376			1,466
Curtailments	—			(2,755		)
Net benefit obligation at end of year	332,141			323,601
Change in plan assets:
Employer contributions	15,398			16,778
Plan participant contributions	59			136
Gross benefits paid	(15,457		)	(16,914		)
Fair value of plan assets at end of year	—			—
Unfunded status at end of year	$	(332,141	)	$	(323,601	)
Amounts recognized in the balance sheet consist of:
Current liabilities	$	(14,734	)	$	(14,892	)
Noncurrent liabilities	(317,407		)	(308,709		)
Accumulated other comprehensive loss	55,123			51,893
Net amount recognized	$	(277,018	)	$	(271,708	)
Amounts recognized in accumulated other comprehensive loss consists of:
Net actuarial loss	$	58,301		$	55,706
Prior service credit	(3,178		)	(3,813		)
	$	55,123		$	51,893

Prior service costs and credits and actuarial gains and losses are amortized over the average life expectancy or average future service of the plan’s participants. In 2018, $3.9 million will be amortized from accumulated other comprehensive loss into net periodic benefit cost.

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONT.)

The components of net periodic postretirement medical benefit cost are as follows:


	Defined Benefit Pension Years Ended December 31,									SERP Years Ended December 31,						Years Ended December 31,
	2014			2013			2012			2014		2013		2012		2017			2016			2015
	(In thousands)															(In thousands)
Components of net periodic benefit cost:
Service cost	$	2,425		$	2,346		$	2,139		$	—	$	—	$	—	$	3,018		$	3,270		$	4,217
Interest cost	7,963			6,209			6,330			168		152		172		12,651			12,353			11,629
Expected return on plan assets	(10,796		)	(8,770		)	(8,241		)			—		—
Settlements and curtailments	4,585			—			—			—		—		—
Amortization of:
Prior service cost	—			—			—			—		—		—
Prior service credit																(635		)	(636		)	(636		)
Actuarial loss	1,217			3,377			2,867			97		112		95		4,298			1,895			1,944
Total net periodic pension cost	$	5,394		$	3,162		$	3,095		$	265	$	264	$	267
Total net periodic benefit cost																$	19,332		$	16,882		$	17,154



Delaware	23-1128670
(State or other jurisdiction of incorporation or organization)	(I.R.S. Employer Identification No.)

9540 South Maroon Circle, Suite ~~200~~ 300, Englewood, CO	80112
(Address of principal executive offices)	(Zip Code)



Title of Each Class		Name of Exchange on Which Registered
Common Stock, par value ~~$2.50~~$0.01 per share		NASDAQ Global Market

~~Depositary Shares, each representing~~ ~~one-quarter of a share of Series A Convertible~~ ~~Exchangeable Preferred Stock~~



Large ~~accelerated filer~~Accelerated Filer		¨☐	Accelerated ~~filer~~Filer	☒
Non-Accelerated Filer (do not check is smaller reporting company)	x☐	Smaller Reporting Company	☐
		Emerging Growth Company
~~Non-accelerated filer~~		¨ ~~(Do not check if a smaller reporting company.)~~	~~Smaller reporting company~~		¨☐


	Coal - U.S.	Coal - Canada	Coal - WMLP⁽²⁾	Total	Coal - U.S.	Coal - Canada	Coal - WMLP²	Total
	(In thousands of tons)				(In thousands of tons)
Coal reserves:⁽¹⁾
Coal reserves¹:
Proven	447,801	606,941	67,720	1,122,462	316,330	274,159	108,786	699,275
Probable	24,383	109,996	8,396	142,775	1,562	19,575	11,730	32,867
Total proven and probable reserves	472,184	716,937	76,116	1,265,237
Total proven and probable reserves³					317,892	293,734	120,516	732,142
Permitted reserves	221,164	597,025	39,184	857,373	161,846	241,966	62,597	466,409
2014 production	28,118	15,729	5,598	49,445
Current year production					18,843	22,462	6,642	47,947



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


Item		Page		Page
	PART I		PART I

1	Business	5	Business	6
1A	Risk Factors	33	Risk Factors	28
1B	Unresolved Staff Comments	53	Unresolved Staff Comments	50
2	Properties	53	Properties	50
3	Legal Proceedings	53	Legal Proceedings	50
4	Mine Safety Disclosure	53	Mine Safety Disclosure	50
	PART II		PART II

5	Market for Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities	54	Market for Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities	51
6	Selected Financial Data	56	Selected Financial Data	53
7	Management’s Discussion and Analysis of Financial Condition and Results of Operations	59	Management’s Discussion and Analysis of Financial Condition and Results of Operations	56
7A	Quantitative and Qualitative Disclosures about Market Risk	74	Quantitative and Qualitative Disclosures about Market Risk	72
8	Financial Statements and Supplementary Data	76	Financial Statements and Supplementary Data	73
9	Changes in and Disagreements with Accountants on Accounting and Financial Disclosure	128	Changes in and Disagreements with Accountants on Accounting and Financial Disclosure	122
9A	Controls and Procedures	128	Controls and Procedures	122
9B			Other Information	125
	PART III		PART III

10	Directors, Executive Officers and Corporate Governance	130	Directors, Executive Officers and Corporate Governance	125
11	Executive Compensation	130	Executive Compensation	125
12	Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters	130	Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters	125
13	Certain Relationships and Related Transactions, and Director Independence	130	Certain Relationships and Related Transactions, and Director Independence	125
14	Principal Accountant Fees and Services	130	Principal Accountant Fees and Services	126
	PART IV		PART IV

15	Exhibits and Financial Statement Schedules	131	Exhibits and Financial Statement Schedules	127
Signatures		132
16			Form 10-K Summary	134
			Signatures	140


~~(1)~~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:


~~(2)~~2	Represents total ~~reserve information~~reserves for WMLP, of which we are the general partner and owner of ~~79%~~93.94% of the total outstanding equity ~~interests.~~interests (as of December 31, 2017).


~~(2)~~	~~We closed the transaction for the purchase of the Alberta and Saskatchewan mines on April 28, 2014. The numbers reported for those mines for 2014~~coal that are ~~reported for the 8 month period from April 28, 2014 to December 31, 2014. Historical tonnage for 2012 and 2013 is not applicable to the Canadian mines.~~ultimately recovered.



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



Coal - WMLP Mines	Cadiz	Tuscarawas	Belmont	New Lexington	Noble⁵	Plainfield⁵	Muhlenberg⁷	Tusky^{5, 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



	Absaloka Mine	Rosebud Mine	Jewett Mine	Beulah Mine	Savage Mine	Kemmerer Mine	Total
Owned by	Westmoreland Resources, Inc.	Western Energy Company	Texas Westmoreland Coal Co.	Dakota Westmoreland Corporation	Westmoreland Savage Corporation	Westmoreland Kemmerer, Inc.
Location	Big Horn County, MT	Rosebud and Treasure Counties, MT	Leon, Freestone and Limestone Counties, TX	Mercer and Oliver Counties, ND	Richland County, MT	Lincoln County, WY
Coal reserves (thousands of tons) Proven	41,791	269,455	24,108	22,504	4,513	85,430	447,801
Probable	—	—	—	15,516	—	8,867	24,383
Total proven and probable reserves (thousands of tons)	41,791	269,455	24,108	38,020	4,513	94,297	472,184
Permitted reserves (thousands of tons)	41,791	100,678	24,108	14,497	4,513	35,577	221,164
2014 production (thousands of tons)	6,612	8,754	5,255	2,764	334	4,399	28,118
Estimated life of permitted reserves⁽¹⁾	2020	2024	2021	2014	2028	2025
Lessor	Ÿ Crow Tribe Ÿ Private parties	Ÿ Federal Government Ÿ State of MT Ÿ Great Northern Properties	Ÿ Private parties	Ÿ Private parties Ÿ State of ND Ÿ Federal Government	Ÿ Federal Government Ÿ Private parties	Ÿ Federal Government Ÿ Private parties
Lease term	Through exhaustion	Varies	Varies	Varies	Varies	Varies
Current production capacity (thousands of tons)	7,500	13,300	7,000	3,400	400	7,000
Coal type	Sub-bituminous	Sub-bituminous	Lignite	Lignite	Lignite	Sub-bituminous
Major customers	Ÿ Xcel Energy Ÿ Western Fuels Assoc. Ÿ Midwest Energy Ÿ Rocky Mountain Power Ÿ Trans Alta	Ÿ Colstrip 1&2 owners Ÿ Colstrip 3&4 owners	Ÿ NRG Texas Power LLC	Ÿ Otter Tail Ÿ MDU Ÿ Northern Municipal Power Agency Ÿ Northwestern Energy	Ÿ MDU Ÿ Sidney Sugars	Ÿ PacifiCorp Ÿ Various industrial customers
Delivery method	Rail / Truck	Truck / Rail / Conveyor	Conveyor	Conveyor / Rail	Truck	Conveyor/ Rail/ Truck
Approx. heat content (BTU/lb.)⁽²⁾	8,509	8,455	6,631	7,090	6,472	9,853
Approx. sulfur content (%)⁽³⁾	0.64	0.69	0.91	0.66	0.54	0.73
Year current complex opened	1974	1968	1985	1963	1958	1950⁽⁴⁾
Total tons mined since inception (thousands of tons)	191,629	465,456	201,982	109,966	16,725	184,266


~~(1)~~	Approximate year in which permitted reserves would be exhausted, based on current mine plan and production rates. The Jewett Mine’s reserves are covered under two separate mining permits, which must be renewed every five years.


~~(2)~~	~~Approximate heat content applies to the coal mined in 2014.~~


~~(3)~~	~~Approximate sulfur content applies to the tons mined in 2014.~~


~~(4)~~	~~The Elkol Underground Mine opened in 1950 and the Sorenson Surface Operations opened in 1963. Tons mined since inception for the Kemmerer Mine are for tons mined from 1950 through 2014.~~



	Cadiz	Tuscarawas	Plainfield	Belmont	New Lexington	Noble	Muhlenberg(5)	Tusky(4)	Total
Owned by	Oxford Mining Company, LLC	Oxford Mining Company, LLC	Oxford Mining Company, LLC	Oxford Mining Company, LLC	Oxford Mining Company, LLC	Oxford Mining Company, LLC	Oxford Mining Company - Kentucky, LLC	Oxford Mining Company, LLC
Location	Harrison County, Ohio	Tuscarawas County, Ohio	Muskingum, Guernsey and Coshocton Counties, Ohio	Belmont County, Ohio	Perry, Athens and Morgan Counties, Ohio	Noble and Guernsey Counties, Ohio	Muhlenberg and McLean Counties, Kentucky	Harrison and Tuscarawas Counties, Ohio
Coal reserves (thousands of tons) Proven	7,148	5,966	3,447	10,122	5,596	1,311	15,165	18,965	67,720
Probable	743	—	—	619	521	16	1,131	5,366	8,396
Total proven and probable reserves (thousands of tons)	7,891	5,966	3,447	10,741	6,117	1,327	16,296	24,331	76,116
Permitted reserves (thousands of tons)	6,097	3,101	265	2,875	1,717	26	8,383	16,720	39,184
2014 production (thousands of tons)	3,074	1,185	—	403	685	251	—	—	5,598
Estimated life of permitted reserves⁽¹⁾	2018	2018	2017	2016	2017	2015	2020+	2025+
Lessor	Private parties	Private parties	Private parties	Private parties	AEP, Private parties	Private parties	Private parties	Private parties
Lease term	Through exhaustion	Through exhaustion	Through exhaustion	Through exhaustion	Through exhaustion	Through exhaustion	Through exhaustion	Through exhaustion
Current production capacity (thousands of tons)	2,604	1,176	—	840	900	240	—	—
Coal type	Bituminous	Bituminous	Bituminous	Bituminous	Bituminous	Bituminous	Bituminous	Bituminous
Major customers	American Electric Power Company, Inc. ; FirstEnergy Corp.; and East Kentucky Power Cooperative	American Electric Power Company, Inc. ; FirstEnergy Corp.; and East Kentucky Power Cooperative	American Electric Power Company, Inc. ; FirstEnergy Corp.; and East Kentucky Power Cooperative	American Electric Power Company, Inc. ; FirstEnergy Corp.; and East Kentucky Power Cooperative	American Electric Power Company, Inc. ; FirstEnergy Corp.; and East Kentucky Power Cooperative	American Electric Power Company, Inc. ; FirstEnergy Corp.; and East Kentucky Power Cooperative	N/A - See Note 2	N/A - See Note 1
Delivery method	Barge, Rail, Truck	Truck	Truck	Barge	Rail	Barge, Truck
Approx. heat content (BTU/lb.)⁽²⁾	11,350	11,775	11,703	11,804	11,177	11,239	11,314	12,900
Approx. sulfur content (%)⁽³⁾	2.70	4.10	4.40	4.30	4.10	4.80	3.60	2.10
Year current complex opened	2000	2003	1990	1999	1993	2006	2009	2003


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


~~(4)~~	WMLP began underground mining at the Tusky mining complex in late 2003 after leasing coal reserves from a third party in exchange for a royalty based on tons sold. In June 2005, WMLP sold the Tusky mining complex, and subleased the associated underground coal reserves to the purchaser in exchange for a royalty. There are 8 years remaining on WMLP's lease for the underground coal reserves, and


~~(5)~~	This mining complex was idled in December 2013 and remained idled throughout year ended December 31, 2014. WMLP is seeking to sell the remaining Illinois Basin equipment, consisting of a large-capacity shovel and several smaller pieces of equipment, and would consider offers for the remaining coal reserves and/or facilities related to the Illinois Basin operations.



	2014
	Reportable Rate	Lost Time Rate
U.S. Operations (excluding WMLP mines)	1.29	0.88
U.S. National Average	1.71	1.19

	Recordable	Lost Time
Canadian Operations (April 28, 2014 through December 31, 2014)	4.82	0.71



	At December 31,
Company/Market/Peer Group	2009		2010		2011		2012		2013		2014
Westmoreland Coal Company	$	100.00	$	134.01	$	143.10	$	104.83	$	216.50	$	372.73
NYSE MKT Composite Index	$	100.00	$	125.53	$	133.39	$	142.30	$	151.25	$	156.94
NASDAQ Financial Index	$	100.00	$	113.56	$	103.72	$	124.50	$	175.23	$	188.39
2014 Peer Group Index	$	100.00	$	147.57	$	84.86	$	65.55	$	57.00	$	35.67
2013 Peer Group Index	$	100.00	$	142.88	$	114.88	$	83.14	$	99.55	$	94.26



	2014
	(In millions)
Increase in interest expense due to increased debt levels	$	(21.9	)
Decrease in our power segment operating income due to the renegotiated ROVA contract, unfavorable power prices and lower demand	(13.4		)
Decrease in our Coal - U.S. segment primarily due to weather impacts as well as rail service issues at our Absaloka Mine	(10.1		)
Increase in our Coal - Canada segment due to the Canadian Acquisition	19.3
Increase due to other factors	0.9
Total	$	(25.2	)



	2013
	(In millions)
Decrease in interest expense due to lower debt levels.	$	2.7
Decrease in our corporate segment operating expenses due primarily to improved performance at our captive insurance entity and one-time recruiting and compensation expenses.	1.9
Increase in our power segment operating income due improved performance and fewer unplanned outages.	1.7
Decrease in our coal segment primarily due to costs incurred to increase production levels at the Absaloka Mine, higher royalty coal mined at the Kemmerer Mine, a contract adjustment related to employee benefit costs, depreciation adjustments and acquisition costs.	(5.3		)
Decrease due to other factors.	(0.2		)
Total	$	0.8


⁽¹⁾	~~Includes acquisition~~Adjusted EBITDA , a non-GAAP measure, is defined and ~~transition costs included~~reconciled to net loss in ~~Selling and administrative~~Item 6 - Selected Financial Data ~~on the Consolidated Statements of Operations and the impact of cost of sales related to the sale of inventory written up to fair value in the Canadian Acquisition.~~.


	Restricted Group			Unrestricted Group			Total			Restricted Group			Unrestricted Group			Total
	(In thousands)									(In millions)
Balance sheet information as of December 31, 2014:
Balance sheet information as of December 31, 2017
Cash and cash equivalents	$	8,069		$	6,189		$	14,258		$	47.2		$	56.1		$	103.3
Total current assets	$	316,544		$	44,227		$	360,771		217.2			125.7			342.9
Total assets	$	1,521,826		$	307,752		$	1,829,578		838.0			551.1			1,389.1
Total current liabilities	$	340,238		$	33,659		$	373,897		856.5			390.6			1,247.1
Total debt	$	809,752		$	175,035		$	984,787		673.0			375.4			1,048.4
Total liabilities	$	1,944,292		$	234,731		$	2,179,023		1,556.0			576.6			2,132.6

Statement of operations information for the year ended December 31, 2014
Statement of operations information for the year ended December 31, 2017										Statement of operations information for the year ended December 31, 2017
Revenues	$	1,115,992		$	—		$	1,115,992		$	862.8		$	521.8		$	1,384.6
Operating costs and expenses	1,156,184			2,783			1,158,967			851.7			493.7			1,345.4
Operating loss	(40,192		)	(2,783		)	(42,975		)
Operating income										11.1			28.1			39.2
Other income and expenses	(128,351		)	(1,622		)	(129,973		)	(65.0		)	(53.3		)	(118.3		)
Loss before income taxes	(168,543		)	(4,405		)	(172,948		)	(53.9		)	(25.2		)	(79.1		)
Income tax expense	232			—			232
Income tax benefit										(5.9		)	—			(5.9		)
Net loss	(168,775		)	(4,405		)	(173,180		)	(48.0		)	(25.2		)	(73.2		)
Less net loss attributable to noncontrolling interest	—			(921		)	(921		)	(1.8		)	—			(1.8		)
Net loss attributable to the Parent company	$	(168,775	)	$	(3,484	)	$	(172,259	)	$	(46.2	)	$	(25.2	)	$	(71.4	)
Adjusted EBITDA										$	128.1		$	141.2		$	269.3



	December 31, 2017		Percent of Consolidated Total
	(In thousands)
Total assets	$	704,802	50.7	%
Total debt	$	13,271	1.3	%
Total liabilities	$	220,326	10.3	%

	Year Ended December 31, 2017		Percent of Consolidated Total
	(In thousands)
Revenues	$	438,272	31.7	%
Adjusted EBITDA	$	90,621	33.6	%


	2015 Expected		2014 Actual		2013 Actual		2012 Actual		2018 Expected		2017 Actual		2016 Actual		2015 Actual
	(In millions)								(In millions)
Postretirement medical benefits	$	12.2	$	11.8	$	12.0	$	12.0	$	12.6	$	11.9	$	13.2	$	13.7
CBF premiums	2.0		2.0		2.2		2.3
Combined benefit fund premiums									1.3		1.4		1.6		1.8
Workers’ compensation benefits	0.4		0.4		0.6		0.5		0.5		0.5		0.4		0.4
Total heritage health payments	14.6		14.2		14.8		14.8		$	14.4	$	13.8	$	15.2	$	15.9

Pension contributions ⁽¹⁾	1.2		4.1		0.6		0.2		$	2.3	$	0.8	$	0.3	$	0.7


~~(1)~~	~~Of the 2014 pension contributions we made $1.9 million through the contribution of Company stock.~~



	Projected Final Reclamation Costs		Reclamation Deposits		Restricted Investments and Bond Collateral		Customer Obligations for Final Reclamation
	(In thousands)
Coal - U.S.	$	500,824	$	77,021	$	16,509	$	333,093
Coal - Canada	194,143		—		52,928		—
Coal - WMLP	77,082		—		37,239		—
Power	3,888		—		—		—
Total	$	775,937	$	77,021	$	106,676	$	333,093


	Payments Due by Period										Payments Due by Period⁽¹⁾
	Total		2015		2016-2017		2018-2019		After 2019		Total		2018		2019-2020		2021-2022		After 2022
	(In thousands)										(In millions)
Long-term debt obligations (principal and interest)	$	1,337,552	$	85,081	$	167,229	$	317,615	$	767,627	$	1,293.5	$	416.7	$	474.2	$	402.6	$	—
Capital lease obligations (principal and interest)	117,054		41,927		67,271		7,659		197		35.7		18.3		13.5		3.9		—
Operating lease obligations	46,783		16,886		16,652		9,303		3,942		23.7		8.7		8.0		3.0		4.0
Other long-term liabilities⁽¹⁾	1,574,772		60,638		127,771		156,623		1,229,740
Benefit plan obligations⁽²⁾											687.5		21.4		42.0		42.9		581.2
Reclamation obligations⁽³⁾											950.0		49.3		105.2		119.0		676.5
Other long-term liabilities											18.2		16.9		1.3		—		—
Totals	$	3,076,161	$	204,532	$	378,923	$	491,200	$	2,001,506	$	3,008.6	$	531.3	$	644.2	$	571.4	$	1,261.7


(1)	Debt obligations are scheduled based on their contractual maturities and are not reflective of any potential accelerations discussed further in Note 8 - Debt And Lines Of Credit to the consolidated financial statements included in Item 8 - Financial Statements and Supplementary Data of this Annual Report on Form 10-K.


(2)	Represents benefit payments for our postretirement medical benefits, black lung, workers’ compensation, and combined benefit fund plans, as well as contributions for our defined benefit pension ~~plans and final~~plans. Shown at undiscounted amounts.


(3)	Future commitments for reclamation ~~costs.~~obligations are shown at inflated, but undiscounted amounts.


	Postretirement Medical Benefits					Postretirement Medical Benefits
Health Care Cost Trend Rate	1% Increase		1% Decrease
	(In thousands)					1% Increase		1% Decrease
1% Change in Health Care Cost Trend Rate						(In millions)
Effect on service and interest cost components	$	2,614	$	(2,096	)	$	2.7	$	(2.1	)
Effect on postretirement medical benefit obligation	$	46,056	$	(37,003	)	48.3		(39.0		)