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RISK FACTORS

Risks Related to the Sherritt Acquisition

We cannot be assured that the Sherritt Acquisition will be completed.

There can be no assurance that the Sherritt Acquisition will be completed, or will be completed in the time frame, on the terms or in the manner currently anticipated, as a result of a number of factors, including, among other things, the failure of one or more of the conditions to closing in the Arrangement Agreement. The conditions to closing of the Sherritt Acquisition, including approval in Canada under the Competition Act and under the Investment Canada Act, as well as a court order from the Court of Queen’s Bench of Alberta and a waiver or consent of a right of first refusal applicable to certain of the Sherritt Assets, may not be satisfied or waived or other events may intervene to delay or result in the failure to close the Sherritt Acquisition. The Arrangement Agreement may be terminated by the parties under certain circumstances, including, without limitation, if the Sherritt Acquisition has not been completed by June 30, 2014 (subject to extension in certain limited circumstances and exceptions). Any delay in closing or a failure to close could have a negative impact on our business.

We and Sherritt will be subject to business uncertainties while the Sherritt Acquisition is pending that could adversely affect our and its business.

Uncertainty about the effect of the Sherritt Acquisition on employees and customers may have an adverse effect on us and the Sherritt Subsidiaries. Although we and Sherritt intend to take actions to reduce any adverse effects, these uncertainties may impair our and their ability to attract, retain and motivate key personnel until the Sherritt Acquisition is completed and for a period of time thereafter. These uncertainties could cause customers, suppliers and others that deal with us and the Sherritt Subsidiaries to seek to change existing business relationships with us and them. Employee retention could be reduced during the pendency of the Acquisition, as employees may experience uncertainty about their future roles. If, despite our and Sherritt’s retention efforts, key employees depart because of concerns relating to the uncertainty and difficulty of the integration process or a desire not to remain with us, our business could be harmed.

The Sherritt Acquisition is subject to receipt of consent or approval from governmental authorities that could delay or prevent the completion of the Sherritt Acquisition or that could cause the abandonment of the Sherritt Acquisition.

To complete the Sherritt Acquisition, we and Sherritt are required to obtain approvals or consents from, or make filings with, certain applicable governmental authorities, including approval in Canada under the Competition Act and under the Investment Canada Act , as well as a court order from the Court of Queen’s Bench of Alberta. While we and Sherritt each believe that we will receive all required approvals, there can be no assurance as to the receipt or timing of receipt of these approvals. Furthermore, the receipt of such approvals may be conditional upon actions that the parties are not obligated to take under the Arrangement Agreement and other related agreements, which could result in the termination of the Arrangement Agreement by us or the other party, or, if such approvals are received, their terms could have a detrimental impact on us following the completion of the Sherritt Acquisition. A substantial delay in obtaining any required authorizations, approvals or consents, or the imposition of unfavorable terms, conditions or restrictions contained in such authorizations, approvals or consents, could prevent the completion of the Sherritt Acquisition or have an adverse effect on the anticipated benefits of the Sherritt Acquisition, thereby adversely impacting our business, financial condition or results of operations.

We may not have uncovered all risks associated with the Sherritt Acquisition and significant liabilities of which we are not aware may exist now or arise in the future.

Upon consummation of the Sherritt Acquisition, we will assume the risk of unknown, and certain known, liabilities at the Sherritt Subsidiaries. The Sherritt Acquisition is structured as a stock purchase in which we will purchase all of the stock and equity interests of the Sherritt Subsidiaries. Once we own the Sherritt Subsidiaries, we will be responsible for all of the liabilities of the Sherritt Subsidiaries other than those for which we are being indemnified by Sherritt. Many of the representations and warranties given by Sherritt in the Arrangement Agreement are limited in scope and limited to the knowledge of certain Sherritt employees. Additionally, many of the representations and warranties are made only with respect to liabilities that would cause a material adverse effect to the Sherritt Subsidiaries. There may be significant liabilities that do not meet this threshold, and therefore are not required to be disclosed to us by Sherritt and for which we will not be indemnified.

 

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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 Sherritt Acquisition or for costs associated with known liabilities that exceed our estimates. A portion of the consideration in the Sherritt Acquisition consists of the assumption of liabilities; accordingly, if those liabilities are greater than we expect, the effective cost of the acquisition could increase significantly. In accordance with the terms of the Arrangement Agreement, we will assume all liabilities attributable to the ownership of the Sherritt Subsidiaries and operation of the Sherritt Assets, regardless of whether incurred before or after the closing date, other than certain specified liabilities retained by Sherritt or for which we are indemnified by Sherritt. Furthermore, although the Arrangement Agreement requires that Sherritt indemnify us for certain losses we may incur in connection with the Sherritt Acquisition, we may not be able to recover all or any portion of such losses if we should elect to pursue any claims we may have against Sherritt pursuant to such indemnification provisions or otherwise.

The pro forma financial information included in this offering memorandum may not be representative of the results of Sherritt Assets after the consummation of the Sherritt Acquisition.

The pro forma financial information in this offering memorandum is presented for illustrative purposes only and may not be indicative of the combined company’s financial position or results of operations that would have actually occurred had the Sherritt Acquisition been completed at or as of the dates indicated, nor is it indicative of our future operating results or financial position. The pro forma financial information has been derived from our historical financial statements and the audited historical financial statements of the Sherritt Subsidiaries (which historical financial information was originally prepared in accordance with IFRS and not GAAP). Additionally, the pro forma financial information does not reflect future non-recurring charges resulting from the Sherritt Acquisition or future events that may occur after the Sherritt Acquisition, including the potential costs or savings related to the planned integration of the Sherritt Assets such as investments in environmental, health and safety matters that we intend to make following the Sherritt Acquisition, and does not consider potential impacts of current market conditions on revenues or expense efficiencies. The pro forma financial information presented in this offering memorandum is based in part on certain assumptions regarding the Sherritt Acquisition that we believe are reasonable under the circumstances. We cannot assure you that our assumptions will prove to be accurate over time.

The Sherritt Acquisition will substantially expand our business, making it difficult to evaluate our business based upon our historical financial information.

The Sherritt Acquisition will significantly increase our size, expand our geographic market, enter us into new lines of business and result in material changes to our revenues and expenses. As a result of the Sherritt Acquisition and our continued goal of targeted reserve acquisitions, our financial results for any period or changes in our results across periods may continue to dramatically change. Our historical financial results, therefore, may not provide an accurate prediction of our future operating results. Accordingly, an evaluation of our business going forward may be difficult.

We may not be able to determine the actual financial condition of the Sherritt Assets until after we complete the Sherritt Acquisition and take control of the Sherritt Assets.

Although we conducted what we believe to be a reasonable level of investigation and diligence regarding the Sherritt Subsidiaries and the Sherritt Assets, a certain level of risk remains regarding the actual operating and financial condition of the Sherritt Assets. For example, the financial information provided to us with respect to the Sherritt Subsidiaries was prepared by Sherritt’s management and any financial statements provided (which form the basis of the pro forma financial statements in this offering memorandum), were originally prepared in accordance with IFRS. We may not, therefore, have a fully accurate understanding of the historical financial condition and performance of the Sherritt Subsidiaries until we actually assume control of the Sherritt Assets and their operations, and may not be able to ascertain the actual value or understand the potential liabilities of the Sherritt Assets until such time as we incorporate them into our operations.

We face challenges with the mine plan at certain of the Sherritt mines that we may not be able to resolve.

We intend to implement mine plan revisions and operational improvements at certain of the Sherritt mines being acquired. There are risks and uncertainties associated with these changes that could result in the planned operational improvements and mine plan revisions being less successful than anticipated, or impossible altogether. For instance, we may be unable to acquire regulatory approvals to initiate mine plan changes that would make operations at certain mines more efficient or profitable. In addition, we may not be able to acquire permit approvals to continue to operate in certain areas, or to mine new areas that would extend the lives of certain Sherritt mines. Finally, the demand and pricing for coal, which we do not control, could affect our ability to sell coal currently produced at certain Sherritt mines, which could result in changes to our plans for mining and developing those properties. Any delay or failure to implement the operational changes we intend to make at the Sherritt mines could adversely impact our anticipated results of operations and business.

 

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We may not realize the anticipated benefits of our acquisition of the Sherritt Assets, including potential synergies, due to challenges associated with integrating the Sherritt Assets or other factors.

The Sherritt Acquisition constitutes a significant acquisition for us. The success of the Sherritt Acquisition will depend in part on the success of our management in efficiently integrating the operations, technologies and personnel of the Sherritt Assets. Our management’s inability to meet the challenges involved in successfully integrating the Sherritt Assets or to otherwise realize the anticipated benefits of the transaction could harm our results of operations.

The challenges involved in the integration of the Sherritt Assets include:

 

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integrating the operations, processes, people and technologies relating to the Sherritt Assets;

 

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coordinating and integrating regulatory, benefits, operations and development functions;

 

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demonstrating to customers that the Sherritt Acquisition will not result in adverse changes in coal quality, delivery schedules and other relevant deliverables;

 

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managing and overcoming the unique characteristics of the Sherritt Assets, such as the specific mining conditions at each of the acquired mines;

 

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assimilating and retaining the personnel of the Sherritt Subsidiaries and integrating the business cultures, operations, systems and clients of the Sherritt Subsidiaries with our own;

 

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consolidating corporate and administrative infrastructures and eliminating duplicative operations and administrative functions; and

 

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identifying the potential unknown liabilities associated with the Sherritt Subsidiaries and Sherritt Assets.

In addition, the overall integration of the Sherritt Assets will require substantial attention from our management, particularly in light of the geographically dispersed operations of the acquired mines relative to our other mines and operations and the unique characteristics of the Sherritt 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 the Sherritt Acquisition 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 Sherritt Acquisition could be adversely impacted to the extent that relationships with existing or potential customers, suppliers or the Sherritt workforce is adversely affected as a consequence of the Sherritt Acquisition, as a result of further weakening of global economic conditions, or by practical or legal constraints on our ability to successfully integrate the operations of the Sherritt Assets.

We cannot assure you that we will successfully or cost-effectively integrate the Sherritt Assets 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.

We incurred and expect to continue to incur significant costs related to the Sherritt Acquisition that could have a material adverse effect on our operating results.

We expect to incur financial, legal, consulting and accounting costs of approximately $8.5 million in connection with the Sherritt Acquisition. We also anticipate that we will incur significant costs in connection with the integration of the Sherritt Assets which cannot be reasonably estimated at this time. These costs may have a material adverse effect on our cash flows and operating results in the periods in which they are recorded.

 

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The acquisition of foreign companies and operations may subject us to additional risks.

We do not currently operate outside the United States. Upon consummation of the Sherritt Acquisition, a significant portion of our assets, operations and revenues will be located in Canada, and we will be subject to risks inherent in business operations outside of the United States. These risks include without limitation:

 

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impact of currency exchange rate fluctuations among the U.S. dollar, the Canadian dollar and foreign currencies relating to Sherritt’s 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;

 

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exchange controls and other limits on our ability to repatriate earnings from other countries;

 

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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;

 

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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;

 

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increased financial accounting and reporting burdens and complexities resulting from the conversion and integration of the Sherritt 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;

 

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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;

 

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difficulties and costs associated with complying with, and enforcement of remedies under, a wide variety of complex domestic and international laws, treaties and regulations;

 

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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 has limited experience managing foreign operations, and 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 Sherritt Assets include an export business, and the Sherritt Acquisition will therefore increase our exposure to the global coal market and the risks associated with exporting into that market.

Currently, we sell our coal production to United States customers, and do not have any significant export operations. The Sherritt Assets include a mine in western Canada that produces premium thermal coal for the Asian export market, and delivers that coal through committed port capacity in western Canada. There are significant financial and operational risks associated with the movement and delivery of coal in international markets with which we have limited experience. Our management team has limited operational experience managing an international coal export business or complying with regulations in multiple jurisdictions. For a discussion of the additional financial and market risks we will be exposed to as a result of our increased participation in the international coal market. In addition, ownership and operation of an export business may result in an increasing amount of our cash and cash equivalents being held outside the U.S. Repatriation of these funds could be subject to delay for local country approvals and could have potentially adverse tax consequences.

 

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Economic conditions in Canada will have a direct impact on our business, financial condition, results of operations and cash flows.

Foreign economies, including the Canadian economy, may differ favorably or unfavorably from the United States economy in growth of gross national product, rate of inflation, market development, rate of savings, and capital investment, resource self-sufficiency and balance of payments positions, and in other respects. As a result of the Sherritt Acquisition, we will own and operate seven producing coal mines in Canada with an aggregate annual production capacity of approximately 27 million tons and total proven and probable reserves of approximately 676 million tons, which sell a substantial majority of their aggregate production to Canadian utilities and other Canadian customers. As of September 30, 2013 on a pro forma basis giving effect to the Sherritt Acquisition, 62% of our property, plant and equipment and reserves would have been owned by our Canadian subsidiaries, and 54% of our revenues would have been attributable to our Canadian operations. Fluctuations in the Canadian economy will therefore directly and indirectly impact both the revenues and cost structure of these Canadian assets. As a result of the foregoing, our business, financial condition, results of operations and cash flows will be in part dependent on economic conditions in Canada.

Upon consummation of the Sherritt Acquisition, we will be subject to foreign exchange risk as a result of exposures to changes in currency exchange rates between the U.S. and Canada.

Upon consummation of the Sherritt Acquisition, we will be exposed to exchange rate fluctuations between the Canadian dollar and U.S. dollar. We will realize revenues from sales made from the Sherritt Assets in Canadian dollars, and many of the expenses incurred by the Sherritt Assets will also be 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. In the event that the Canadian dollar weakens in comparison to the U.S. dollar, earnings generated from Canadian operations will translate into reduced earnings in our consolidated statements of comprehensive loss reported in U.S. dollars. In addition, our Canadian subsidiaries also record certain accounts receivable and accounts payable, which are denominated in Canadian dollars. Foreign currency transactional gains and losses are realized upon settlement of these assets and obligations.

Following the Sherritt Acquisition, fluctuations in the U.S. dollar relative to the Canadian dollar may make it more difficult to perform period-to-period comparisons of our reported results of operations. For purposes of accounting, the assets and liabilities of our Canadian operations will be translated using period-end exchange rates, and the revenues and expenses of our Canadian operations will be translated using average exchange rates during each period. Translation gains and losses are reported in accumulated other comprehensive loss as a component of stockholders’ equity.

The historical financial statements and resource reserve reporting of the Sherritt Subsidiaries differ from financial and reserve reporting in the United States.

The historical financial statements of the Sherritt Subsidiaries and the historical reserve and resource estimates and reports regarding the Sherritt Assets are not directly comparable to our financial statement and reserve report filings that are subject to SEC reporting and disclosure requirements. Sherritt and the Sherritt Subsidiaries have historically produced their financial statements and reports and reported reserves and resources in accordance with Canadian practices. Those practices are different from the practices used by us. In particular, we use GAAP as our primary set of financial reporting standards, whereas Sherritt has historically produced its financial statements under IFRS. The SEC also has specific rules applicable to the measurement and reporting of resource reserves of U.S. companies that differ from the Canadian reserve reporting requirements applicable to Sherritt. Accordingly, the financial information and statements and reserves and resources information contained in the reports filed by Sherritt with Canadian securities regulators and provided to our management in connection with the Sherritt Acquisition, are not directly comparable to our reserve and resources reporting information that is subject to the reporting and disclosure requirements of the SEC.

The Obed Mine Release into the Athabasca River prior to the Sherritt Acquisition may result in significant liability arising after closing of the Sherritt Acquisition.

On October 31, 2013, a breach of an onsite water containment pond occurred at Sherritt’s Obed Mountain Mine near Hinton, Alberta. The contents of the release included 670,000 cubic meters of process water and low concentrations of suspended solids, mainly, clay, soil, shale and particles of coal. The released sediment, including organic debris it collected in its path, entered the Athabasca River. Sherritt notified the environmental regulators immediately upon discovery of the breach. On November 19, 2013, Alberta Environment and Sustainable Resource Development issued an environmental protection order. The order requires Sherritt to develop and implement assessment, management and remediation plans relating to the impact of the Obed Mine Release. Such plans will include short- and long-term plans for impact assessment, the recovery of solids, wildlife mitigation, waste management and mine wastewater management. Current work continues on impact assessment, next-stage remediation activities and the finalization of short-, medium- and long-term monitoring plans. After closing of the Sherritt Acquisition, Sherritt will work with the regulators and us on the remediation plan. Although the Arrangement Agreement requires that Sherritt indemnify us for losses resulting from the Obed Mine Release, we may not be able to recover all of such losses if we should elect to pursue any claims we may have against Sherritt pursuant to such indemnification provisions or otherwise.

 

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Canadian licenses, permits and other authorizations may be subject to challenges based on Aboriginal or Treaty rights.

Section 35 of the Canadian Constitution Act of 1982, the Natural Resources Transfers Agreements of 1930 and certain Canadian judicial decisions have recognized and affirmed the continued existence of Aboriginal and Treaty rights in Canada, including in some circumstances title to lands continuously used or occupied by Aboriginal groups, as well as harvesting and other rights relating to Aboriginal groups’ traditional territories. In most cases, the precise nature and contours of these rights as well as their geographic scope remain undefined at this time, and are or may be the subject to ongoing or future claims, court cases and negotiations of significant complexity.

Pending resolution of such claims, the Supreme Court of Canada has also recognized a Crown obligation to consult with and, in some circumstances, accommodate Aboriginal interests where the Crown undertakes actions or contemplates decisions that could adversely affect claimed or established Aboriginal or Treaty rights. While this duty lies with the federal and provincial Crowns, it may have a significant impact on private mineral and other proprietary interests.

Westmoreland’s mineral and other proprietary interests may now or in the future be the subject of Aboriginal land or rights claims. The impact of any such claims on Westmoreland’s mineral and other proprietary cannot be predicted with any degree of certainty and no assurance can be given that a recognition of Aboriginal rights in the area in which Westmoreland’s mineral and other proprietary rights are located, by way of a negotiated settlement or judicial pronouncement, would not have an adverse effect on Westmoreland’s activities.

As issues relating to Aboriginal and Treaty rights and consultation continue to be argued, developed and resolved in Canadian courts, Westmoreland will continue to cooperate, communicate and exchange information and views with Aboriginal groups and government, and participate with the Crown in its consultation processes with Aboriginal groups in order to foster good relationships and minimize risks to mineral rights and operational plans. Due to their complexity, it is not expected that the issues regarding Aboriginal and Treaty rights or consultation will be finally resolved in the short term and, accordingly, the impact of these issues on mineral and other proprietary rights and on mining operations is unknown at this time.

Should a dispute arise between one or more Aboriginal groups and the Crown, it could significantly affect Westmoreland’s mineral and other proprietary interests and operations. Also, such action could have a detrimental impact on Westmoreland`s financial condition and results of operations as well as on customers.

Sherritt has significant operations in Cuba the funding of which with Acquisition Proceeds potentially could implicate U.S. Office of Foreign Assets Control (“OFAC”) restrictions.

Sherritt has provided assurances in the Arrangement Agreement that no proceeds from the Sherritt Acquisition will be used to fund or support any of its operations in Cuba. These assurances were based on specific review of past funding practices for Cuban operations. If Sherritt were to violate these contractual terms and use proceeds in a manner that funded or supported its Cuban operations, depending on the circumstances of that use, it is possible that OFAC could consider Sherritt’s use of these funds to implicate OFAC restrictions. If that occurred and depending on the circumstances, OFAC might pursue fines, penalties and other sanctions against Sherritt. Whether Westmoreland would be implicated in such an enforcement action would depend on the circumstances of the alleged non-compliance. Whether the contractual terms would serve to mitigate any alleged non-compliance on the part of Westmoreland would depend on circumstances and OFAC’s assessment of the relevant contract terms and the specific review conducted in support of those terms.

Because we are acquiring Sherritt’s royalty business and immediately selling that business, we could have liability with respect to the royalty business buyer.

We are acquiring Sherritt’s royalty business and immediately selling that business to Altius. We are not familiar with the royalty assets, have limited information regarding these assets and have not had and will not have operational control over these assets. Sherritt is making certain representations and warranties to us and to Altius regarding the royalty assets; however, this does not prevent Altius from pursuing claims against us with respect to the royalty assets they are acquiring.

 

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Risks relating to taxation and reassessment

The Arrangement Agreement provides that, in connection with the transfer of the Royalty Interest to Altius, the reorganization transactions Sherritt has undertaken in preparation for the transfer of the Royalty Interest and the Sherritt Acquisition itself, applicable tax returns and elections will be prepared and filed so as to comply with the Income Tax Act (Canada) and all applicable provincial tax legislation in Canada. However, such returns are subject to review and reassessment by the applicable taxation authority. PMRL and CVRI, after their acquisition by us pursuant to the Arrangement Agreement, may potentially be subject to higher than expected past or future tax liability, as well as interest and penalties, in the event of a successful reassessment, and such amounts could be material. Sherritt has agreed to indemnify us for certain tax matters and liabilities that may arise after closing of the Sherritt Acquisition. 

Risk Factors Relating to our Combined Operations

Risks associated with being leveraged.

Following the completion of the Sherritt Acquisition and the WML Refinancing, we expect to have outstanding indebtedness of approximately $828 million, and a net leverage ratio of 3.3 (calculated by subtracting available cash from gross debt and dividing by EBITDA). We may also incur additional indebtedness in the future, including additional indebtedness of $70 million (which we may increase to $100 million at our discretion) under our Revolving Credit Facility if we complete our anticipated amendment of that facility. Our leverage position may, among other things:

 

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limit our ability to obtain additional debt financing in the future for working capital, capital expenditures, acquisitions, or other general corporate purposes;

 

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require us to dedicate a substantial portion of our cash flow from operations to service our debt, reducing the availability of cash flow for other purposes;

 

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increase our vulnerability to economic downturns, limit our ability to capitalize on significant business opportunities, and restrict our flexibility to react to changes in market or industry conditions; or

 

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make it more difficult to pay our debts, including payment on our outstanding notes, which will mature in 2018.

While we have received credit upgrades from both S&P and Moody’s within the last two years, on December 26, 2013, following the announcement of the Sherritt Acquisition, Moody’s Investor Service placed our ratings on watch for potential downgrade and there can be no assurance that rating agencies will not downgrade the credit rating on our outstanding indebtedness in the future. Any such downgrade, or any perceived decrease in our creditworthiness, could impede our ability to refinance existing debt or secure new debt or otherwise increase our future cost of borrowing and could create additional concerns on the part of our customers, partners, investors and employees about our financial condition and results of operations.

If we fail to comply with certain covenants in our various debt arrangements, it could negatively affect our liquidity and ability to finance our operations.

Our lending arrangements contain, among other terms, events of default and various affirmative and negative covenants. Should we be unable to comply with any future debt-related covenant, we will be required to seek a waiver of such covenant to avoid an event of default. Covenant waivers and modifications may be expensive to obtain, or, potentially, unavailable. If we are in breach of any covenant and are unable to obtain covenant waivers and our lenders accelerate our debt, we could attempt to refinance the debt or repay the debt by selling assets and applying the proceeds from such sales to the debt. Sales of assets undertaken in response to such immediate needs may be prohibited under our lending arrangements without the consent of our lenders, may be made at potentially unfavorable prices, or asset sales may not be sufficient to refinance or repay the debt, and we may be unable to complete such transactions in a timely manner, on favorable terms, or at all.

We may not generate sufficient cash flow at our operating subsidiaries to pay our operating expenses, meet our debt service costs and pay our heritage and corporate costs.

Our WML subsidiary, which owns the Rosebud, Jewett, Beulah and Savage mines, is currently subject to the WML Credit Facility that limits its ability to dividend funds to us. While we expect to terminate the WML Credit Facility if we are successful in amending our Revolving Credit Facility to the increase the amount of borrowings available thereunder, if we are not successful in doing so the WML Credit Facility will remain in effect. In that event, WML may not be able to pay dividends to us in the amounts and in the time required for us to pay our heritage health costs and corporate overhead expenses. Ultimately, if WML’s operating cash flows are insufficient to support its operations, amortize its debt and provide dividends to us in the amounts and time required to pay our expenses, we may be required to expend cash on hand or further leverage our operations through our Revolving Credit Facility or other borrowings to fund our heritage liabilities and corporate overhead. Should we be required to expend cash on hand to fund such activities, such funds would be unavailable to grow our business through strategic acquisitions or ventures or support the business through reclamation bonding, capital and reserve acquisition.

 

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As a mine mouth operator, we provide coal to a small group of customers. This dependence could adversely affect our revenues if such customers reduce or suspend their coal purchases or if they become unable to pay for our coal.

During the nine months ended September 30, 2013, we derived approximately 67% of our total revenues from coal sales to five power plants: Colstrip Units 3&4 (18%), Naughton Power Station (16%), Limestone Generating Station (14%), Colstrip Units 1 & 2 (13%) and Coyote Station (6%). Similarly, for full-year 2013, the Sherritt Subsidiaries sold approximately 25% of their total aggregate coal production to two customers, SaskPower (13%) and Capital Power (12%). 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. Five of our six mines are dedicated to supplying customers located adjacent to or near the mines, and these mines may have difficulty identifying alternative purchasers of their coal if their existing customers suspend or terminate their purchases.

Additionally, certain of our long-term contracts are set to expire in the next several years. Our contracts with the Sherburne County Station are three-year rolling contracts, with one-third of the tonnage expiring on an annual basis. Our contract with Coyote Station, located adjacent to our Beulah mine and averaging approximately 3 million tons of coal sold per year, expires in May 2016 and is not expected to be renewed. Our contract with Colstrip Units 3 & 4 expires in December 2019. Should we be unable to successfully renew any or all of these expiring contracts, the reduction in the sale of our coal would adversely affect our operating results and liquidity and could result in significant impairments to the affected mine should the mine be unable to execute a new long-term coal supply agreement. The long term agreements we are acquiring under the Sherritt Acquisition have long remaining terms with the exception of the contract applicable to Poplar River mine which is set to expire in 2015.

Similarly, interruption in the purchase of power by Dominion could also negatively affect our revenues. During the nine months ended September 30, 2013, the sale of power by ROVA to Dominion accounted for approximately 14% of our consolidated revenues. Although ROVA supplies power to Dominion under long-term power purchase agreements, if Dominion 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.

Our ability to collect payments from our customers could be impaired if their creditworthiness deteriorates.

Our ability to receive payment for coal sold and delivered depends on the continued creditworthiness of our customers. If we determine that a customer is not creditworthy, we may not be required to deliver coal under the customer’s coal sales contract. If this occurs, we may decide to sell the customer’s coal on the spot market, which may be at prices lower than the contracted price, or we may be unable to sell the coal at all. Furthermore, the bankruptcy of any of our customers could materially and adversely affect our financial position. In addition, competition with other coal suppliers could cause us to extend credit to customers and on terms that could increase the risk of payment default.

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, 2012, the projected benefit obligation under our defined benefit pension plans was $172.3 million and the fair value of plan assets was $121.9 million. The difference between plan obligations and assets, or the funded status of the plans, significantly affects the net periodic benefit cost and ongoing funding requirements of those plans. Among other factors, changes in interest rates, mortality rates, early retirement rates, investment returns and the market value of plan assets can affect the level of plan funding, cause volatility in the net periodic benefit cost and increase our future funding requirements. During the nine months ended September 30, 2013, we made no contributions to these pension plans and accrued $2.6 million in expenses related thereto. The current economic environment increases the risk that we may be required to make even larger contributions in the future. Additionally, due to covenants in our WML Notes, we are required to maintain our pension plan funding at higher levels than would otherwise be required, increasing funding requirements and the chance that we will be required to make large contributions in the future.

 

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If our assumptions regarding our future expenses related to employee benefit plans are incorrect, then expenditures for these benefits could be materially higher than we have assumed. In addition, we may have exposure under those plans that extend beyond what our obligations would be with respect to our own employees.

We provide various postretirement medical benefits and worker’s compensation benefits to current and former employees and their dependents. We calculate the total accumulated benefit obligations according to guidance provided by GAAP. We estimate the present value of our postretirement medical, black lung and worker’s compensation benefit obligations to be $333.8 million, $16.2 million and $9.5 million, respectively, at December 31, 2012. In addition, in connection with the Sherritt Acquisition, we assumed the 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 Industry Retiree Health Benefit Act of 1992, or Coal Act, which provides for the funding of health and death benefits for certain UMWA retirees. Our contributions to these funds totaled $1.7 million, $2.3 million and $2.6 million during the nine months ended September 30, 2013 and for the years ended December 31, 2012 and 2011, respectively. Our contributions to these funds could increase as a result of a shrinking contribution base as a result of the insolvency of other coal companies that currently contribute to these funds, lower than expected returns on fund assets or other funding deficiencies.

We could also have obligations under the Tax Relief and Health Care Act of 2006, or 2006 Act. The 2006 Act authorized up to a maximum of $490 million in federal contributions to pay for certain benefits, including the healthcare costs under certain funds created by the Coal Act for “orphans,” i.e. retirees from companies that subsequently ceased operations, and their dependents. However, if Congress were to amend or repeal the 2006 Act or if the $490 million authorization were insufficient to pay for these healthcare costs, we, along with other contributing employers and certain affiliates, would be responsible for the excess costs.

We also contribute to a multi-employer defined benefit pension plan, the Central Pension Fund of the Operating Engineers, or Central Pension Fund, on behalf of employee groups at our Rosebud, Absaloka and Savage mines that are represented by the International Union of Operating Engineers. The Central Pension Fund is subject to certain funding rules contained in the Pension Protection Act of 2006, or 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, 2012, 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 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.

In connection with the Sherritt Acquisition, we are assuming responsibility for and accepting obligations under the following pension plans:

 

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Prairie Mines & Royalty Lt. Pension Plan for Salaried Employees;

 

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Prairie Mines & Royalty Lt. Pension Plan for Non-Union Employees;

 

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Boundary-Bienfait Hourly Defined Benefit Pension Plan;

 

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Boundary-Bienfait Hourly Defined Contribution Pension Plan;

 

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Sherritt Executive Supplementary Pension Plan; and,

 

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Sherritt Non-Union Pension Plan.

We have evaluated these plans, and believe that certain of them may be underfunded by immaterial amounts. In the event the underfund amounts are larger than we anticipate, the Arrangement Agreement requires Sherritt to adjust the purchase price if such underfunded amount exceeds $3,000,000.

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 GAAP pursuant to 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.

 

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Our reserve estimates may prove to be incorrect.

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

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

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

 

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quality of the coal;

 

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

 

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the percentage of coal ultimately recoverable;

 

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

 

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

 

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

 

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

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

If the assumptions underlying our reclamation and mine closure obligations are materially inaccurate, we could be required to expend greater amounts than anticipated.

We are subject to stringent reclamation and closure standards for our mining operations. We calculated the total estimated reclamation and mine-closing liabilities according to the guidance provided by GAAP and current industry practice. Estimates of our total reclamation and mine-closing liabilities are based upon permit requirements and our engineering expertise related to these requirements. If our estimates are incorrect, we could be required in future periods to spend materially different amounts on reclamation and mine-closing activities than we currently estimate. Likewise, if our customers, some of whom are contractually obligated to pay certain reclamation costs, default on the unfunded portion of their contractual obligations to pay for reclamation, we could be forced to make these expenditures ourselves and the cost of reclamation could exceed any amount we might recover in litigation.

 

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We estimate that our gross reclamation and mine-closing liabilities, which are based upon projected mine lives, current mine plans, permit requirements and our experience, were $263.2 million (on a present value basis) at September 30, 2013. Of these September 30, 2013 liabilities, our customers have assumed $91.9 million by contract. In addition, we held final reclamation deposits, received from customers, of approximately $74.4 million at September 30, 2013 to provide for these obligations. We estimate that our obligation for final reclamation that was not the contractual responsibility of others or covered by offsetting reclamation deposits was $96.9 million at December 31, 2012. We must recover this $96.9 million from revenues generated by coal sales. In addition, based on the conversion to GAAP of Sherritt’s historical IFRS financial statements, we estimate that in connection with the Sherritt Acquisition we will assume approximately $123.1 million of additional reclamation and mine-closing liabilities.

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

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

We are required to provide bonds to secure our obligations to reclaim lands used for mining. We must post a bond before we obtain a permit to mine any new area. These bonds are typically renewable on a yearly basis. Bonding companies are requiring that applicants collateralize increasing portions of their obligations to the bonding company. In 2012, we paid approximately $7.2 million in premiums for reclamation bonds and were required to use $25.6 million in cash to collateralize approximately 24% of the face amount of the new bonds obtained in 2012, mostly due to the Kemmerer acquisition. We anticipate that, as we permit additional areas for our mines, our bonding and collateral requirements could increase. Any cash that we provide to collateralize our obligations to our bonding companies is not available to support our other business activities. Our results of operations could be negatively affected if the cost of our reclamation bonding premiums and collateral requirements were to increase. Additionally, if we are unable to obtain additional bonding capacity due to cash flow constraints, we will be unable to begin mining operations in newly permitted areas, which would hamper our ability to efficiently meet our current customer contract deliveries, expand operations, and increase revenues. We anticipate being required to use approximately $58.0 million to collateralize new bonds in connection with the Sherritt Acquisition.

Our coal mining operations are subject to external conditions that could disrupt operations and negatively affect our results of operations.

Our coal mining operations are all surface mines. These mines are subject to conditions or events beyond our control that could disrupt operations, affect production, and increase the cost of mining at particular mines for varying lengths of time. These conditions or events include: unplanned equipment failures, geological 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; and weather conditions. For example, in our recent past, we have endured a major blizzard at the Beulah Mine, a trestle fire at the Beulah Mine, and an unanticipated replacement of boom suspension cables on one of our draglines, all of which interrupted deliveries. Major disruptions in operations at any of our mines over a lengthy period could adversely affect the profitability of our mines.

In addition, unplanned outages of draglines and extensions of scheduled outages due to mechanical failures or other problems occur from time-to-time and are an inherent risk of our coal mining business. Unplanned outages typically increase our operation and maintenance expenses and may reduce our revenues because of selling fewer tons of coal. If properly maintained, a dragline can operate for 40 years or longer. The average age of Westmoreland’s draglines is 30 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. The average age of our shovels is 15 years. As our draglines, shovels and other major equipment ages, we may experience unscheduled maintenance outages or increased maintenance costs, which would adversely affect our operating results.

 

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Unplanned outages and extensions of scheduled outages due to mechanical failures or other problems occur from time-to-time at our power plant customers and are an inherent risk of our business. Unplanned outages typically increase our operation and maintenance expenses and may reduce our revenues because of selling fewer tons of coal. For example, in November 2011, the Sherburne County station experienced an explosion and fire that has caused an extended outage. As a result, we lost approximately 50% of our coal sales in 2012 at our Absaloka Mine. While 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. We maintain business interruption insurance coverage to lessen the impact of events such as this, and have received $6.0 million and $13.4 million of cash proceeds for the three and nine months ended September 30, 2013, respectively 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. 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.

Our operations are vulnerable to natural disasters, operating difficulties and infrastructure constraints, not all of which are covered by insurance, which could have an impact on our productivity.

Mining and power operations are vulnerable to natural events, including blizzards, earthquakes, drought, floods, fire, storms and the possible effects of climate change. Operating difficulties such as unexpected geological variations could affect the costs and viability of our operations. Our operations also require reliable roads, rail networks, power sources and power transmission facilities, water supplies and IT systems to access and conduct operations. The availability and cost of infrastructure affects our capital expenditures, operating costs, and planned levels of production and sales.

We maintain insurance for some, but not all, of the potential risks and liabilities associated with our business. For some risks, we may not obtain insurance if we believe the cost of available insurance is excessive relative to the risks presented. As a result of market conditions, premiums and deductibles for certain insurance policies can increase substantially, and in some instances, certain insurance may become unavailable or available only for reduced amounts of coverage. As a result, we may not be able to renew our existing insurance policies or procure other desirable insurance on commercially reasonable terms, if at all. Although we maintain insurance at levels we believe are appropriate and consistent with industry practice, we are not fully insured against all risks. In addition, pollution and environmental risks and consequences of any business interruptions such as equipment failure or labor disputes generally are not fully insurable. Losses and liabilities from uninsured and underinsured events and delay in the payment of insurance proceeds could have a material adverse effect on our financial condition, results of operations and cash flows.

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

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 or upgrades to controls to improve regional haze 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 is set for late in 2014. 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 starting in approximately 2015. 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.

 

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

In September 2013, EPA reproposed new source performance standards for greenhouse gases (“GHG”) that would require new fossil-fuel fired power plants to install carbon capture and sequestration systems. EPA stated that it intends to finalize the rule by June of 2014. EPA also is developing GHG standards for existing power plants, initial draft proposals of which EPA has indicated it expects to release June 1, 2014.

In Canada, on September 12, 2012 the federal government 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. PMRL’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 estimate the extent to which such regulations will impact the Sherritt Assets to be acquired by us. However, the Sherritt Assets to be acquired by us 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. In addition to directly emitting GHGs, the Sherritt Assets to be acquired by us 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.

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 the ICTC, the loss of which will adversely affect the financial condition of the operation.

The ICTC were set to expire in December, 2013 unless the relevant provisions of the Internal Revenue Code were extended or renewed by the U.S. Congress. The ICTC have not been extended or renewed. 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 Coal LLC by the investor did not continue after December 31, 2013. While we are actively seeking a new partner, there can be no assurance that we will be able to find a new partner in a timely manner, or, if and when we are able to find a new partner, that they will agree to a partnership on the same terms. Since 2009, we have experienced a yearly average of $3.0 million of income and $6.2 million of cash receipts from Absaloka Coal LLC’s participation in ICTC transactions.

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

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

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

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

Transportation impediments may hinder our current operations or future growth.

Certain segments of our current business, principally our Absaloka Mine and the Coal Valley mine we are acquiring in the Sherritt Acquisition, rely on rail transportation for the delivery of coal product to customers and ports. Our ability to deliver our product in a timely manner could be adversely affected by the lack of adequate availability of rail capacity, whether because of work stoppages, union work rules, track conditions or otherwise. In 2011, flooding conditions disrupted rail service to the Absaloka Mine, resulting in lost revenue. Rail or shipping transportation costs represent a significant portion of the total cost of coal for our customers, and the cost of transportation is a key factor in a customer’s purchasing decision. In addition, the Coal Valley mine exports the majority of its production to the global seaborne market through port facilities 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.

 

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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.

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

At September 30, 2013, approximately 64% of our total workforce was represented by labor unions including the International Union of Operating Engineers, the UMWA, the Communications, Energy and Paperworkers Union of Canada and the International Brother of Electrical Workers. Our unionized workforce is spread out amongst the majority of our surface mines. As a majority of our workforce is unionized, there may be an increased risk of strikes and other labor disputes, and our ability to alter labor costs is subject to collective bargaining. The collective bargaining agreement relating to the represented workforce at the Absaloka Mine expired in mid-2011. We were successful in negotiating a new agreement without any work stoppages or other disruptions. In 2012, we were successful in entering into agreements with our workforce at Savage, Kemmerer and Rosebud. If our Jewett Mine operations were to become unionized, we could be subject to additional risk of work stoppages, other labor disputes and higher labor costs, which could adversely affect the stability of production and our results of operations. While strikes are generally a force majeure event in long-term coal supply agreements, thereby exempting the mine from its delivery obligations, the loss of revenue for even a short time could have a material adverse effect on our financial results.

Congress has proposed legislation to enact a law allowing workers to choose union representation solely by signing election cards, which would eliminate the use of secret ballots to elect union representation. While the impact is uncertain, if the government enacts this proposal into law, which would make it administratively easier to unionize, it may lead to more coal mines becoming unionized.

The workforce of the Sherritt Subsidiaries is also unionized and will increase the percentage of our workforce represented by a labor union. There are labor agreements in place with one or more unions at each of the producing Sherritt mines we are acquiring other than the Genesee mine. One of the agreements at the Poplar River Mine recently expired. However, a memorandum of understanding for a new agreement was signed in January 2014, and Sherritt management anticipates approval of the new agreement in early February. The agreement at the Coal Valley mine expires on February 28, 2014, and negotiations with the Union began in mid-January. We believe Sherritt has good relations with its unionized employees and representative unions. However, if we are not successful in negotiating new labor agreements with any of the Sherritt workforce unions or otherwise maintain strong partnerships with them following the Sherritt Acquisition, 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.

We face intense competition to attract and retain employees.

We are dependent on retaining existing employees and attracting additional qualified employees to meet current and future needs. We face intense competition for qualified employees, and there can be no assurance that we will be able to attract and retain such employees or that such competition among potential employers will not result in increasing salaries. We rely on employees with unique skill sets to perform our mining operations, including engineers, mechanics and other highly skilled individuals. An inability to retain existing employees or attract additional employees, especially with mining skills and background, could have a material adverse effect on our business, cash flows, financial condition and results of operations.

 

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Risk Factors Relating to the Coal and Power Industries

The risk of prolonged recessionary conditions could adversely affect our financial condition and results of operations.

Because we sell substantially all of our coal to electric utilities, our business and results of operations remain closely linked to demand for electricity. Recent economic uncertainty has raised the risk of prolonged recessionary conditions. Historically, global demand for basic inputs, including electricity production, has decreased during periods of economic downturn. If demand for electricity production decreases, our financial condition and results of operations could be adversely affected.

Competition in the North American coal industry may adversely affect our revenues and results of operations.

Many of our competitors in the North American coal industry are major coal producers who have significantly greater financial resources than we do. The intense competition among coal producers may impact our ability to retain or attract customers and may therefore adversely affect our 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.

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.

The electric utility industry currently accounts for approximately 93% of coal consumption in the U.S. and 80% of coal consumption in 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 price of coal, which could negatively impact our results of operations and liquidity. We do not have the right to sell fixed quantities of coal, so revenue can fall even though we have long-term contracts.

Some power plants are fueled by natural gas because of the relatively lower construction costs of such plants compared to coal-fired plants and because natural gas is a cleaner burning fuel. In addition, some states have adopted or are considering legislation that encourages domestic electric utilities to switch from coal-fired power generation plants to natural gas powered plants. Similar legislation has been implemented or is under consideration in several Canadian provinces. Passage of these and other state or federal laws or regulations limiting carbon dioxide emissions could result in fuel switching, from coal to other fuel sources, by purchasers of our coal. Such laws and regulations could also mandate decreases in carbon dioxide emissions from coal-fired power plants, impose taxes on carbon emissions or require certain technology to capture and sequester carbon dioxide from coal-fired power plants. If these or similar measures are ultimately imposed by federal or state governments or pursuant to international treaty, our reserves and operating costs may be materially and adversely affected. Similarly, alternative fuels (non-fossil fuels) could become more attractive than coal in order to reduce carbon emissions, which could result in a reduction in the demand for coal and, therefore, our revenues.

Recently, the supply of natural gas has reached record highs and the price of natural gas has remained at depressed levels for sustained periods, making it an attractive competing fuel. A continuing decline in the price of natural gas, or continuing periods of sustained low natural gas prices, could cause demand for coal to decrease, result in fuel switching and decreased coal consumption by electricity-generating utilities and adversely affect the price of our coal. Sustained low natural gas prices may cause utilities to phase-out or close existing coal-fired power plants or reduce construction of any new coal-fired power plants, which could have a material adverse effect on demand and prices received for our coal.

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

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

 

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currency exchange rates;

 

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growth of economic development;

 

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price of alternative sources of electricity or steel;

 

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worldwide demand for coal and other sources of energy; and

 

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ocean freight rates.

 

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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 Sherritt Assets include a mine in western Canada that primarily supplies premium thermal coal to the Asian export market. Ownership of this mine will increase our exposure to price fluctuations in the international coal market, and a substantial downturn in demand in the Asian market could have a material adverse effect on our financial condition and results of operations.

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

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

 

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limitations on land use;

 

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employee health and safety;

 

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mandated benefits for retired coal miners;

 

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mine permitting and licensing requirements;

 

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reclamation and restoration of mining properties after mining is completed;

 

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air quality standards;

 

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discharges to water;

 

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

 

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protection of human health, plant life and wildlife;

 

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discharge of materials into the environment;

 

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effects of mining on groundwater quality and availability; and

 

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remediation of contaminated soil, surface and groundwater.

The costs, liabilities and requirements associated with these and other regulations may be costly and time-consuming and may delay commencement or continuation of exploration or production operations. Failure to comply with these regulations may result in the assessment of administrative, civil and criminal penalties, the imposition of cleanup and site restoration costs and liens, the issuance of injunctions to limit or cease operations, the suspension or revocation of permits and 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.

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.

 

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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.

Greenhouse gas, or GHG, emissions have increasingly become the subject of international, national, state and local attention. Coal-fired power plants can generate large amounts of carbon and other 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 and/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 notice of finding and 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 GHGs under existing provisions of the federal Clean Air Act. The EPA has begun to implement GHG-related reporting and permitting rules. Similarly, the U.S. Congress has considered, and in the future may again consider, “cap and trade” legislation that would establish a cap on emissions of GHGs covering much of the economy in the United States and would require most sources of GHG emissions to obtain GHG emission “allowances” corresponding to their annual emissions of GHGs. In addition, coal-fired power plants, including new coal-fired power plants or capacity expansions of existing plants, have become subject to opposition by environmental groups seeking to curb the environmental effects of GHG emissions. Most recently, President Obama in June 2013 announced a Climate Action Plan, which included a Presidential Memorandum directing the EPA to issue standards for GHG emissions from existing, modified and reconstructed fossil-fuel fired power plants, and the EPA issued a revised proposal with standards for new fossil fuel-fired plants, including coal-fired plants, in September 2013.

In Canada, in September 2012 the federal government released final regulations for reducing GHG emissions from coal-fired electricity generation through the Canadian CO2 Regulations. The Canadian CO2 Regulations will require certain Canadian coal-fired electricity generating units, effective July 1, 2015, to achieve an average annual emissions intensity performance standard of 420 tons of CO2 per gigawatt hour. According to Sherritt’s public filings, 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 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 50 years from the unit’s commissioning date. New and end-of-life units that incorporate technology for carbon capture and sequestration may apply for a temporary exemption from the performance standard that would remain in effect until 2025, provided that certain implementation milestones are met. Provincial equivalency agreements, under which the Canadian CO2 Regulations would stand down, are being negotiated or discussed with the provinces of Alberta and Saskatchewan. The Prairie coal production in the long-term could be reduced unless certain existing units or new units of the customers served by the Prairie operations are equipped with carbon capture and storage or other technology that achieves the prescribed performance standard, the impact of the Regulations is altered by equivalency agreements, or the Canadian CO2 Regulations are changed to lower the performance standard. The impact of the Canadian CO2 Regulations on existing units will vary by location and province.

In addition, various Canadian provincial governments and other regional initiatives are moving ahead with GHG reduction and other initiatives designed to address climate change. For example, under the Climate Change and Emissions Management Act (the “CCEM”), the Province of Alberta enacted the “Specified Gas Emitters Regulation.” As of January 1, 2008, this enactment requires certain existing facilities with direct emissions of 100,000 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 2011 compliance period, CVRI’s Coal Valley operations exceeded the 100,000 ton emissions threshold established under the Specified Gas Emitters Regulation, and Coal Valley was required to contribute to the Climate Change and Emissions Management Fund. According to Sherritt’s public filings, for the 2012 compliance period, the preliminary calculations indicate Coal Valley will be required to purchase fund credits. It is anticipated that for the next several years, emissions intensity at Coal Valley 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 or more of CO2e to report their annual GHG emissions in accordance with the specified Gas Reporting Standard published by the Government of Alberta. In Saskatchewan, Bill 126, The Management and Reduction of Greenhouse Gases Act, was passed in 2010 but is not yet proclaimed in force. The legislation provides a framework for the control of GHG emissions by regulated emitters and will be proclaimed once accompanying draft regulations are finalized.

 

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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 the Sherritt Assets to be acquired by us. However, those assets 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 operation. 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, the Sherritt Assets to be acquired by us 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 of the developments in the U.S. discussed above that may affect our customers and demand for our coal could also affect us directly through adverse impacts on ROVA.

Depending on how they evolve, such developments, individually or in the aggregate, may have a material adverse effect on our business, results of operations, and financial performance.

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

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

The EPA intends to issue or has issued a number of significant regulations that will impose more stringent requirements relating to air, water and waste controls on electric generating units. These rules include the EPA’s pending new requirements for coal combustion residue (“CCR”) management that may further regulate the handling of wastes from the combustion of coal. In addition, in February 2012, the EPA signed a rule to reduce emissions of mercury and toxic air pollutants from new and existing coal- and oil-fired electric utility steam generating units, often referred to as the MATS Rule.

Considerable uncertainty is associated with air emissions initiatives. New regulations are in the process of being developed, and many existing and potential regulatory initiatives are subject to review by federal or state agencies or the courts. Stringent air emissions limitations are either in place or are likely to be imposed in the short to medium term, and these limitations will likely require significant emissions control expenditures for many coal-fired power plants. For example, the owners of Units 3 and 4 at Colstrip, adjacent to our Rosebud 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.

 

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The regulation of air emissions in Canada may also reduce the demand for the products of the Sherritt Assets to be acquired by us. Specifically, the Alberta Environmental Protection and Enhancement Act (“EPEA”) 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 the Sherritt Assets, which in turn could, over time, significantly reduce the demand for the coal produced from the Sherritt Assets.

The customers of the Sherritt Assets in Canada must also comply with a variety of environmental laws that regulate and restrict air emissions, including the EPEA and its regulations, and the CEPA, 1999. Because many of these customers’ activities generate air emissions from various sources, compliance with these laws requires our customers in Canada to make investments in pollution control equipment and to report to the relevant government authorities if any emissions limits are exceeded or are made in contravention of the applicable regulatory requirements.

These laws restrict the amount of pollutants that our Canadian customer’s facilities can emit or discharge into the environment. The NPRI, for example, is created under authority of the CEPA, 1999 and is a Canada-wide, legislated, and publicly accessible inventory of specific substances that are released into the air, water, and land. The purpose of the NPRI was to provide comprehensive national data on releases of specified substances, and assists with, identifying priorities for action, encouraging voluntary action to reduce releases, tracking the progress of reductions in releases, improving public awareness and understanding of substances released into the environment, and supporting targeted initiatives for regulating the release of substances.

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

The Combined Company

Currently, our operations are organized into two principal operating segments, coal and power; and two non-operating segments, heritage and corporate. Upon the consummation of the Sherritt Acquisition, which we expect to occur by the end of the first quarter of 2014, we plan to operate our business through three new principal operating segments, Coal – US, Coal – Canada and Power, and one non-operating segment, Corporate.

Following the Sherritt Acquisition, our business will be conducted through 13 North American surface coal mines, a char production facility that sells to barbeque briquette producers, and a 50% interest in an activated carbon plant with the Cabot corporation. Following the Sherritt Acquisition, we will employ approximately 2,900 employees. We will be the sixth largest North American coal producer as measured by 2012 production, with aggregate production of nearly 50 million tons, and we believe that we will be the largest dragline operator in North America with 27 operating draglines.

For the fiscal year ended December 31, 2012, Westmoreland had $600 million in revenues and $105 million in adjusted EBITDA. The Sherritt Subsidiaries had $709 million in revenues and $157 million in adjusted EBITDA under GAAP. For the twelve months ended September 30, 2013, Westmoreland had $660 million in revenues and $116 million in adjusted EBITDA. For the same period, the Sherritt Subsidiaries had $683 million in revenues and $119 million in adjusted EBITDA under GAAP. On a pro forma basis, after giving effect to the Sherritt Acquisition, the combined company (i) in Fiscal 2012, had $1,310 million in revenues and $263 million in adjusted EBITDA and (ii) for the twelve months ended September 30, 2013, had $1,343 million in revenues and $235 million in adjusted EBITDA.

Our financial statements in the future will differ in material respects from the historical financial statements of Westmoreland, which will significantly affect the comparability of our financial results in the future.

 

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The Sherritt Acquisition will be accounted for as a business combination in accordance with FASB ASC Topic 805. For purposes of this unaudited pro forma condensed combined financial information, the Sherritt Acquisition price has been allocated to the tangible assets acquired and liabilities assumed based on a preliminary estimate of those assets and liabilities. The actual amounts recorded upon finalization of the purchase price allocation may differ materially from the information presented in the accompanying unaudited pro forma condensed combined financial information. Our financial statements issued after the completion of the Sherritt Acquisition will reflect such fair values, which may materially differ from the amounts allocated to such tangible and intangible assets in the historical financial statements of the Sherritt Subsidiaries and will determine a new basis in such assets that will be reflected in our accounting. In addition, the Sherritt Acquisition will result in an increase in our leverage, leading to an increase in interest expense. As a result, amounts presented in our future consolidated financial statements and footnotes will not be comparable with those of historical periods and with the pro forma financial statements included in this offering memorandum.

Summary of Significant Challenges Faced by the Company in 2013 and Thereafter

We face significant challenges in operating our business, including the following:

 

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Integration of the Sherritt Acquisition. The Sherritt Acquisition constitutes a significant acquisition for our business, both in terms of the size and complexity of our combined businesses following the acquisition and the challenge of using our existing support systems to manage the Sherritt Assets. Our management will be required to devote time and attention to the process of integrating the businesses and operations of the Sherritt Subsidiaries with our business and operations, which may decrease the time management will have to conduct the operation of our business in the ordinary course. If we do not manage these integration challenges successfully, they could cause interruptions in our business activities, inconsistencies in our operations, standards, controls, procedures and policies, a deterioration in our employee and customer relationships, increased costs of integration and harm to our reputation. In addition, the acquisition and integration of the Sherritt Assets into our business may not achieve the desired growth and positive market impact we are expecting.

 

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

 

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Renewal of long-term coal supply agreements. We sell almost all of our coal and electricity production under long-term agreements. Our long-term coal contracts typically are either cost plus or cost indexed. Cost indexed contracts may adjust the price of coal in accordance with changes in 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 both cost plus and cost indexed 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 types of 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. If these significant contracts are not renewed or are renewed with less attractive terms, our result of operations will be harmed.

 

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High leverage. We are highly leveraged. Our debt repayment obligations are significant. If we are unable to service our debt, we would face significant consequences, as described in greater detail under. We have a substantial amount of indebtedness, which may adversely affect our cash flow, our ability to operate our business and our ability to satisfy our obligations under the Notes.

 

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Industry regulation. We operate in a highly regulated industry. Onerous environmental and health regulations could cause our business to suffer and could result in our having to modify, reduce or eliminate certain of our operations.

 

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Effect of the Sherritt Acquisition on Liquidity and Capital Resources

We expect a number of factors to result in differences in our results of operation, financial condition and liquidity in 2014 relative to 2013. Among other things, we expect:

 

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increased revenues, profits and operating cash flows as a result of the Sherritt Acquisition;

 

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our overall coal tons delivered to double as a result of the Sherritt Acquisition;

 

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an increase in our depreciation, depletion, amortization and accretion expenses in 2014 due primarily to the Sherritt Acquisition;

 

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to make additional capital investments during 2014 of approximately $75 million to $85 million to improve our mining operations and decrease our equipment maintenance costs;

 

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higher overall levels of cash and liquidity throughout 2014 as a result of the Sherritt Acquisition, as well as under our Revolving Credit Facility, if we are able to increase the amount available as we intend to do following the consummation of the Sherritt Acquisition;

 

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an increase in capital lease obligation payments partially offset by a decrease in term debt payments resulting from the pay-off of the WML Notes;

 

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our interest expense and interest payments will increase in 2014; and

 

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increased bond collateral costs of approximately $58 million due to the Sherritt Acquisition.

Following and the Sherritt Acquisition, we expect our primary sources of liquidity to be cash from operations, cash on hand and available borrowing capacity. As a result of increases in operating profits, the benefits of the cash flow from the Sherritt Acquisition and a decrease in our heritage health benefit costs, we anticipate that our cash from operations, cash on hand and available borrowing capacity will be sufficient to meet our cash requirements for the foreseeable future. However, our expectations in this regard are subject to numerous uncertainties, including uncertainties relating to our operating performance, general market conditions and whether and when we will increase the borrowing capacity under our Revolving Credit Facility. In addition, our capital needs may be greater than we currently expect if we were to pursue one or more additional significant acquisitions.

Following the Sherritt Acquisition, we expect to have the following Canadian Customers.

Paintearth. The Paintearth Mine supplies approximately 3 million tons per year to its mine mouth customer ATCO. The mine received permits in 2012 for a mine extension.

Sheerness. The Sheerness Mine supplies approximately 3.3 million tons per year to its mine mouth customer ATCO. Sherritt is currently exploring adjacent properties for greenfield expansion opportunities.

Boundary Dam. The Boundary Dam Mine in Saskatchewan supplies approximately 5.7 million tons per year to its mine mouth customer SaskPower.

Poplar River. The Poplar River Mine in Saskatchewan supplies approximately 3.5 million tons per year to its mine mouth customer SaskPower.

Bienfait. The Bienfait Mine in Saskatchewan supplies approximately 0.6 million tons per year to SaskPower, domestic consumers and the char & activated carbon plants.

Genesee. The Genesee Mine in Alberta supplies approximately 5.0 million tons per year to its mine mouth customer Capital Power. Under the Genesee Mine’s long-term coal supply contract with Capital Power, direct operating costs are reimbursed to Prairie by Capital Power.

Coal Valley. The Coal Valley mine produced approximately 4.0 million tons of low-sulfur, thermal coal in 2012, primarily for the export market.

Obed. The Obed surface mine ceased production in 2013 and is currently in reclamation.

 

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Properties

Our mines have chosen to permit coal reserves on an incremental basis and, given the current rates of mining and demand, have sufficient permitted coal to maintain production for the periods shown in the table below. We secure all of our final reclamation obligations by reclamation bonds as required by the respective state regulatory authorities. We perform reclamation activities at each mine in the normal course of operations contemporaneously with ongoing coal production.

 

		Reserves				End of Mine Life				Years
		000s Tons								Years
United States
Absaloka			59,186				2021				8
Rosebud			306,949				2052				39
Jewett			34,487				2021				8
Beulah			43,198				2032				19
Savage			5,284				2031				18
Kemmerer			103,674				2037				24
Canada
Genesee			222,777				2055				42
Poplar River			115,081				2041				28
Boundary Dam			175,929				2040				27
Sheerness			46,628				2024				11
Paintearth			29,432				2022				9
Bienfait			64,595				2034				21
Coal Valley			19,180				2018				5
Obed			2,866				n.a.				n.a.

Material Effects of Regulation

We are subject to extensive regulation with respect to environmental and other matters by federal, state, provincial and local authorities. Federal laws to which we are subject include the Surface Mining Control and Reclamation Act of 1977, or SMCRA, the Clean Air Act, the Clean Water Act, the Toxic Substances Control Act, the Endangered Species Act, the Comprehensive Environmental Response, Compensation and Liability Act, the Emergency Planning and Community Right to Know Act and the Resource Conservation and Recovery Act. The United States Environmental Protection Agency, or EPA, and/or other authorized federal or state agencies administer and enforce these laws. Non-compliance with federal, tribal and state and provincial laws and regulations could subject us to material administrative, civil or criminal penalties or other liabilities, including suspension or termination of operations. In addition, we may be required to make large and unanticipated capital expenditures to comply with future laws, regulations or orders as well as future interpretations and more rigorous enforcement of existing laws, regulations or orders. Our reclamation obligations under applicable environmental laws will be substantial. Certain of our coal sales agreements contain government imposition provisions that allow the pass-through of compliance costs in some circumstances.

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. In 2012, our Rosebud Mine received the Sentinels of Safety award in the large surface coal category.

During 2012, we continued to maintain reportable and lost time incident rates significantly below national averages as indicated in the table below.

 

		2012
		Reportable Rate				Lost Time Rate
WCC Mines			1.12				0.48
National Surface Mines			1.65				1.13

Following passage of The Mine Improvement and New Emergency Response Act of 2006, amending the Federal Mine Safety and Health Act of 1977, the U.S. Mine Safety and Health Administration (“MSHA”) significantly increased the oversight, inspection and enforcement of safety and health standards and imposed safety and health standards on all aspects of mining operations. There has also been a dramatic increase in the dollar penalties assessed by MSHA for citations issued over the past two years. Most of the states in which we operate have inspection programs for mine safety and health. Collectively, federal and state safety and health regulations in the coal mining industry are perhaps the most comprehensive and pervasive systems for protection of employee health and safety affecting any segment of U.S. industry.

 

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Regulation in the United States

Federal laws in the United States to which we are subject include the Surface Mining Control and Reclamation Act of 1977, or SMCRA, the Clean Air Act, the Clean Water Act, the Toxic Substances Control Act, the Endangered Species Act, the Comprehensive Environmental Response, Compensation and Liability Act, the Emergency Planning and Community Right to Know Act and the Resource Conservation and Recovery Act. The United States Environmental Protection Agency, or EPA, and/or other authorized federal or state agencies administer and enforce these laws. The following provides brief summaries of these laws and regulations and their effects upon us:

Surface Mining Control and Reclamation Act. SMCRA establishes minimum national operational, reclamation and closure standards for all surface coal mines. SMCRA requires that comprehensive environmental protection and reclamation standards be met during the course of and following completion of coal mining activities. Permits for all coal mining operations must be obtained from the Federal Office of Surface Mining Reclamation and Enforcement, or OSM, or, where state regulatory agencies have adopted federally approved state programs under SMCRA, the appropriate state regulatory authority. States that operate federally approved state programs may impose standards that are more stringent than the requirements of SMCRA and OSM’s regulations and, in many instances, have done so. Permitting under SMCRA has generally become more difficult in recent years, which adversely affects the cost and availability of coal purchased by ROVA, especially in light of significant permitting issues affecting the Central Appalachia region. This difficulty in permitting also affects the availability of coal reserves at our coal mines.

It is our policy to comply in all material respects with the requirements of the SMCRA and the state and tribal laws and regulations governing mine reclamation. In 2012, our Jewett Mine received the 2012 Railroad Commission of Texas Core Mining Reclamation Award for its innovative techniques in stream channel restoration.

Clean Air Act and Related Regulations. The federal Clean Air Act and comparable state laws that regulate air emissions affect coal mining operations both directly and indirectly. Direct impacts on coal mining and processing operations include Clean Air Act permitting requirements and emission control requirements relating to air pollutants, including particulate matter, which may include controlling fugitive dust. The Clean Air Act indirectly affects coal mining operations by extensively regulating the emissions of particulate matter, sulfur dioxide, nitrogen oxides, mercury and other compounds emitted by coal-fired power plants. It also affects us directly because ROVA is subject to significant regulation under the Clean Air Act. In recent years, Congress has considered legislation that would require increased reductions in emissions of sulfur dioxide, nitrogen oxide and mercury, as well as GHGs. The air emissions programs, regulatory initiatives and standards that may affect our operations, directly or indirectly, include, but are not limited to, the following:

 

•

Greenhouse Gas Emissions Standards. In April 2012, the EPA proposed new limits on greenhouse gas emissions from new EGUs under Section 111 of the Clean Air Act (“GHG NSPS”). The proposed limits are referred to as “new source performance standards” because they apply only to new or reconstructed sources. The proposal required all new fossil-fuel-fired EGUs to emit no more than 1,000 pounds of CO2 / megawatt hour on an average annual basis, which is based on the CO2 emissions from natural gas combined cycle facilities. The EPA later indicated its intention to issue a new proposal in light of over 2 million comments on the April 2012 proposal and ongoing developments in the industry. In June 2013, President Obama directed the EPA to issue that new proposal by September 30, 2013, and to finalize it in a timely manner. In September 2013, the EPA revoked its April 2012 proposal and instead proposed new limits, which would require all new coal-fired EGUs to emit no more than 1,100 pounds of CO2 / megawatt hour on an average annual basis, and new natural gas-fired plants to meet a standard of either 1,000 or 1,100 pounds of CO2 / megawatt hour (depending on size). Under the Clean Air Act, new source performance standards like the GHG NSPS have binding effect from the date of proposal. Once NSPSs are finalized, EPA must issue guidance to states for the issuance of existing source standards. The GHG NSPS as currently proposed may be a major obstacle to the construction and development of any new coal-fired generation capacity because it is unlikely, with a few possible exceptions, that the limits in the proposal can be achieved by a new coal-fired EGU without the use of carbon capture and sequestration technology.

 

•

Mercury Air Standards. In February 2012, the EPA published national emission standards under Section 112 of the Clean Air Act setting limits on hazardous air pollutant emissions from coal- and oil-fired electric generating units (“EGUs”). The “Mercury Air Toxics Standards,” or “MATS Rule,” is expected to be one of the most costly rules ever issued by the EPA. It has also proven highly controversial, drawing numerous legal challenges in the U.S. Court of Appeals for the D.C. Circuit as well as petitions for administrative reconsideration filed with the EPA. While the MATS Rule will generally require all coal- and oil-fired EGUs to reduce their hazardous air pollutant emissions, it is particularly problematic for any new coal-fired sources. This is because the new-source limits are so low that they cannot be accurately measured and vendors of pollution control equipment have said they cannot provide commercial guarantees that the limits can be achieved. And because such guarantees are a precondition to obtaining financing in the marketplace, the MATS Rule effectively amounts to a ban on the construction of new coal-fired EGUs. In July 2012, however, the EPA agreed to reconsider the new source standards in response to requests by industry. In November 2012, the EPA published proposed new source standards with revised, less stringent, emission limits. In April 2013, the EPA published new new-source limits under the MATS Rule, and then 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 2013, certain environmental organizations and industry groups filed appeals of the rule as revised.

 

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National Ambient Air Quality Standards (“NAAQS”) for Criteria Pollutants. The Clean Air Act requires the EPA to set standards, referred to as NAAQS, for six common air pollutants, including nitrogen oxide and sulfur dioxide. Areas that are not in compliance (referred to as non-attainment areas) with these standards must take steps to reduce emissions levels. Meeting these limits may require reductions of nitrogen oxide and sulfur dioxide emissions. Although our operations are not currently located in non-attainment areas, we could be required to incur significant costs to install additional emissions control equipment, or otherwise change our operations and future development if that were to change. On June 22, 2010, the EPA published a final rule that tightens the NAAQS for sulfur dioxide. On February 17, 2012 the EPA published final NAAQS for nitrogen dioxide. On January 15, 2013, EPA published final NAAQS for particulate matter; EPA lowered the annual standard for particles less than 2.5 micrometers in diameter but maintained the NAAQS for particles less than 10 micrometers in diameter. Non-attainment designations were set for sulfur dioxide in February 2013 and were set for nitrogen dioxide in January 2012. State implementation plans are due in the winter of 2014 and the deadline to achieve attainment is the summer of 2017. We do not know whether or to what extent these developments might affect our operations or our customers’ businesses. In 2008, EPA finalized the current 8-hour ozone standard. EPA agreed to reconsider the standard, and in 2010 EPA proposed to further reduce the standard. Under orders from President Obama, this NAAQS was not finalized and review is ongoing. A proposal for a lower standard was expected during 2013, but the EPA has not yet published any.

 

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Clean Air Interstate Rule and Cross-State Air Pollution Rule. (“CAIR”) and Cross-State Air Pollution Rule (“CSAPR”). The CAIR calls for power plants in 28 states and the District of Columbia to reduce emission levels of sulfur dioxide and nitrogen oxide pursuant to a cap-and-trade program similar to the system now in effect for acid rain. In 2008, the U.S. Court of Appeals for the District of Columbia Circuit found that the CAIR was fatally flawed, but ultimately agreed to allow it to remain in place pending the EPA’s development of a replacement rule because of concerns about potential disruptions. In June 2011, the EPA finalized the CSAPR as a replacement rule to the CAIR, which requires 28 states in the Midwest and eastern seaboard of the United States to reduce power plant emissions that cross state lines and contribute to ozone and/or fine particle pollution in other states. Under the CSAPR, the first phase of the nitrogen oxide and sulfur dioxide emissions reductions would commence in 2012 with further reductions effective in 2014. On December 15, 2011, the EPA finalized a supplemental rulemaking 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 US 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 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 US Supreme Court seeking review of the Court of Appeals decision, and the Supreme Court granted those petitions in June 2013. The Supreme Court heard oral arguments in December 2013 and will likely issue a decision by June 2014.

 

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Other Programs. A number of other air-related programs may affect the demand for coal and, in some instances, coal mining directly. For example, the EPA has initiated a regional haze program designed to protect and improve visibility at and around national parks, national wilderness areas and international parks. The EPA’s new source review program under certain circumstances requires existing coal-fired power plants, when modifications to those plants significantly change emissions, to install the more stringent air emissions control equipment required of new plants, and concerns about potential failures to comply have resulted in a number of high-profile enforcement actions and settlements over the years resulting in some instances in settlements under which operators install expensive new emissions control equipment. The Acid Rain program under Title IV of the Clean Air Act continues to impose limits on overall sulphur dioxide and nitrogen oxide emissions from regulated EGUs. There is pending litigation to force the EPA to list coal mines as a category of air pollution sources that endanger public health or welfare under Section 111 of the Clean Air Act and establish standards to reduce emissions from sources of methane and other emissions related to coal mines after the EPA declined in 2013 to take such action, not based on the merits but citing resource constraints.

 

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Effect on Westmoreland Coal Company. Our mines do not produce “compliance coal” for purposes of the Clean Air Act. Compliance coal is coal containing 1.2 pounds or less of sulfur dioxide per million British thermal unit, or Btu. This restricts our ability to sell coal to power plants that do not utilize sulfur dioxide emission controls and otherwise leads to a price discount based, in part, on the market price for sulfur dioxide emission allowances under the Clean Air Act. Our coal also contains about fifty percent more ash content than our primary competitors, which can translate into a cost disadvantage where post-combustion coal ash must be land filled. We are at particular risk of changes in applicable environmental laws with respect to the Jewett Mine, whose customer, the NRG Texas Power- Limestone Station, blends our lignite with compliance coal from Wyoming. Tightened nitrogen oxide and new mercury emission standards could result in an increased blend of the Wyoming coal to reduce emissions. Further, increased market prices for sulfur dioxide emissions and increased coal ash costs could also favor an increased blend of the lower ash Wyoming compliance coal. In such a case, NRG Texas Power has the option to increase its purchases of other coal, reduce purchases of our coal, or to terminate our contract. If NRG terminates the contact, sales of lignite would end and the Jewett Mine would commence final reclamation activities. NRG would pay for all reclamation work plus a margin.

 

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Clean Water Act. The Clean Water Act or CWA and corresponding state and local laws and regulations affect coal mining and power generation operations by restricting the discharge of pollutants, including dredged or fill materials, into waters of the U.S. The CWA provisions and associated state and federal regulations are complex and subject to amendments, legal challenges and changes in implementation. Legislation that seeks to clarify the scope of the CWA jurisdiction is under consideration by Congress. Recent court decisions, regulatory actions and proposed legislation have created uncertainty over CWA jurisdiction and permitting requirements that could either increase or decrease the cost and time spent on CWA compliance.

Endangered Species Act. The Federal Endangered Species Act ESA and similar state laws protect species threatened with extinction. Protection of endangered and threatened species may cause us to modify mining plans or develop and implement species-specific protection and enhancement plans to avoid or minimize impacts to endangered species or their habitats. A number of species indigenous to the areas where we operate are protected under the ESA. Based on the species that have been identified and the current application of applicable laws and regulations, we do not believe that there are any species protected under the ESA or state laws that would materially and adversely affect our ability to mine coal from our properties.

Resource Conservation and Recovery Act. We may generate wastes, including “solid” wastes and “hazardous” wastes that are subject to the federal Resource Conservation and Recovery Act, or 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. There have been several legislative proposals that would require the EPA to further regulate the storage of CCR. Any significant changes in the management of CCR could increase our customers’ operating costs and potentially reduce their ability to purchase coal. In addition, in June 2010 the EPA released a proposal with two possible options for the regulation of CCR. One would regulate the CCR as hazardous or special waste and the other would classify the CCR as non-hazardous waste. Under both options, the EPA would establish dam safety requirements to address the structural integrity of surface impoundments to prevent catastrophic releases. The EPA conducted additional information collections in late 2011; however, the EPA had not finalized CCR rules nor established a timeline for finalization. The EPA did not address in the proposed regulations the use of CCR as minefill, but indicated that it would separately work with the Office of Surface Mining in order to develop effective federal regulations ensuring that such placement is adequately controlled. In April 2012, several environmental organizations filed suit against the EPA to compel the EPA to take action on the proposed rule. If CCR were classified as a special or hazardous waste, regulations may impose restrictions on ash disposal, provide specifications for storage facilities, require groundwater testing and impose restrictions on storage locations, which could increase our and our customers’ operating costs and potentially reduce their ability to purchase coal. In addition, contamination caused by the past disposal of CCR, including coal ash, can lead to material liability for our customers under RCRA or other federal or state laws and potentially reduce the demand for coal.

Comprehensive Environmental Response, Compensation, and Liability Act. Under the Comprehensive Environmental Response, Compensation, and Liability Act, also known as CERCLA or Superfund, and similar state laws, responsibility for the entire cost of cleanup of a contaminated site, as well as natural resource damages, can be imposed upon current or former site owners or operators, or upon any party who released one or more designated “hazardous substances” at the site, regardless of the lawfulness of the original activities that led to the contamination. CERCLA also authorizes the EPA and, in some cases, third parties to take actions in response to threats to public health or the environment and to seek to recover from the potentially responsible parties the costs of such action. In the course of our operations, we may have generated and may generate wastes that fall within CERCLA’s definition of hazardous substances. We may also be an owner or operator of facilities at which hazardous substances have been released by previous owners or operators. We may be responsible under CERCLA for all or part of the costs of cleaning up facilities at which such substances have been released and for natural resource damages. We have not, to our knowledge, been identified as a potentially responsible party under CERCLA, nor are we aware of any prior owners or operators of our properties that have been so identified with respect to their ownership or operation of those properties. We also must comply with reporting requirements under the Emergency Planning and Community Right-to-Know Act and the Toxic Substances Control Act.

 

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Climate Change Legislation and Regulations. Numerous proposals for federal and state legislation have been made relating to greenhouse gas, or 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 a number of states in the northeastern and mid-Atlantic regions of the US in a program known as the Regional Greenhouse Gas Initiative (often referred to as “RGGI”) 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 GHGs under existing provisions of the federal Clean Air Act. The EPA has begun to implement GHG-related reporting and permitting rules as described above.

The impact of GHG-related legislation and regulations, including a “cap and trade” structure, on us will depend on a number of factors, including whether GHG sources in multiple sectors of the economy are regulated, the overall GHG emissions cap level, the degree to which GHG offsets are allowed, the allocation of emission allowances to specific sources and the indirect impact of carbon regulation on coal prices. We may not recover the costs related to compliance with regulatory requirements imposed on us from our customer due to limitations in our agreements.

Passage of additional state or federal laws or regulations regarding GHG emissions or other actions to limit carbon dioxide emissions could result in fuel switching from coal to other fuel sources by electricity generators and thereby reduce demand for our coal or indirectly the prices we receive in general. In addition, political and regulatory uncertainty over future emissions controls have been cited as major factors in decisions by power companies to postpone new coal-fired power plants. If these or similar measures, such as controls on methane emissions from coal mines, are ultimately imposed by federal or state governments or pursuant to international treaties, our operating costs or our revenues may be materially and adversely affected. In addition, alternative sources of power, including wind, solar, nuclear and natural gas could become more attractive than coal in order to reduce carbon emissions, which could result in a reduction in the demand for coal and, therefore, our revenues. Similarly, some of our customers, in particular smaller, older power plants, could be at risk of significant reduction in coal burn or closure as a result of imposed carbon costs. The imposition of a carbon tax or similar regulation could, in certain situations, lead to the shutdown of coal-fired power plants, which would materially and adversely affect our coal and power plant revenues.

Bonding Requirements. Federal and state laws require mine operators to assure, usually through the use of surety bonds, payment of certain long-term obligations, including the costs of mine closure and the costs of reclaiming the mined land. The costs of these bonds have fluctuated in recent years, and the market terms of surety bonds have generally become more favorable to us. Surety providers are requiring smaller percentages of collateral to secure a bond, which will require us to provide less cash to collateralize bonds to allow us to continue mining. These changes in the terms of the bonds have been accompanied, at times, by an increase in the number of companies willing to issue surety bonds. As of December 31, 2012, we have posted an aggregate of $316.5 million in surety bonds for reclamation purposes, with approximately $53.0 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. We are evaluating whether 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. The landfills are lined and we believe they meet North Carolina Department of Solid Waste regulations.

An important factor relating to the impact of GHG-related legislation and regulations and any other environmental regulations on our Power segment will be our ability to recover the costs incurred to comply with any regulatory requirements that the government ultimately imposes. We may not 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.

 

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Regulation in Canada

Our Canadian operations are subject to extensive environmental, health and safety laws including: employee health and safety; air quality; water quality and availability; the protection and enhancement of the environment (including the protection of plants and wildlife); land-use zoning; development approvals; the generation, handling, use, storage, transportation, release, disposal and cleanup of regulated materials, including wastes; and the reclamation and restoration of mining properties after mining is completed. Mining operations in Canada are regulated primarily by provincial legislation, although we must also comply with applicable federal legislation and local by-laws.

Provincial Environmental Legislation. In Alberta, the EPEA and its accompanying regulations establish stringent environmental requirements relating to the release of substances into the environment, the designation of contaminated sites, remediation, cleanup, waste minimization, recycling and waste management, reclamation, conservation and disclosure. The EPEA also governs the conduct of environment impact assessments of new projects, existing operations and mine closures. The EPEA requires that an approval be obtained for the construction, operation or reclamation of a mine, quarry and/or coal processing plant. Generally, approvals for such coal mining activities may be granted for up to 10 years but in some cases may expire on the date that the final reclamation certificate is granted. The provisions of the Water Act (Alberta) seek to support and promote the conservation and management of water, including the wise allocation and use of water. An approval and/or license is required to be obtained from Alberta Environment before undertaking certain activities in a water body, before diverting and using surface or ground water, or before the construction of certain works.

Under the CCEM, Alberta enacted the Specified Gas Emitters Regulation.

As of January 1, 2008, this enactment requires certain existing facilities with direct emissions of 100,000 tonnes 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 a new facility, the net emissions intensity limits are dependent on the number of years in which the new facility has been in commercial operation.

The Alberta government requires security bonding to be posted for mine reclamation obligations based in part upon the estimated costs to reclaim disturbed lands. This obligation for security may be satisfied by way of irrevocable letters of credit or guarantees, cash, cheques or other similar negotiable instruments, government guaranteed bonds, debentures, term deposits, certificates of deposit, trust certificates or investment certificates assigned to the Minister of Finance and Enterprise, performance bonds or surety bonds and qualifying environmental trusts within the meaning of the Income Tax Act (Canada).

In Saskatchewan, environmental matters relating to mining operations are governed primarily by the Environmental Management and Protection Act, 2002 (the “EMPA”). EMPA and its regulations establish requirements relating to the release of substances into the environment, effluent releases, contaminated sites, hazardous substances, release reporting, waterworks systems, and reclamation. Under the EMPA and its regulations, releases or discharges of pollutants into the environment are prohibited unless in accordance with certain permits or approvals issued in relation to operations or facilities. Approvals, typically issued for a one to five-year term, are routinely renewed. Developments, including mining developments, in Saskatchewan may be subject to review under Saskatchewan’s Environmental Assessment Act.

The Clean Air Act of Saskatchewan regulates emissions from industrial source incinerators and fuel burning equipment, while The Water Security Agency Act, regulates the use and diversion of surface and ground water. The EMPA and its regulations also specifically regulate the decommissioning, abandonment and reclamation of a mine and related operations. The Saskatchewan government has a reclamation assurance requirement that exists under EMPA’s regulations.

In 2010, the Government of Saskatchewan introduced enabling legislation to move towards a Results Based Regulation model. To support the new results-based approach, several key pieces of enabling legislation were modernized and introduced in the fall 2009 legislative session and passed by the legislature in spring 2010: The Environmental Assessment Amendment Act 2010, The Forest Resources Management Amendment Act 2010, The Environmental Management and Protection Act 2010 and The Management and Reduction of Greenhouse Gases Act. Only the amendments to The Environmental Assessment Amendment Act 2010 are currently in force (proclaimed November 2012), with the changes to the other legislation noted, currently awaiting proclamation.

The proposed Saskatchewan Environmental Code will be a legally binding, enforceable set of requirements to be followed by anyone conducting activities regulated by any of the acts that reference the code. The initial set of chapters of the Environmental Code is expected to be adopted shortly. Work will continue on the code as standards and regulations are updated and new chapters are added.

 

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Federal Environmental Legislation. Coal mining frequently involves crossing, impounding, diverting and using surface waters. Such activities can require approval under federal legislation in Canada such as the federal Fisheries Act, for the construction of a project that may result in serious harm to fish that are part of a commercial, recreational or Aboriginal fishery, or to fish that support such a fishery, or the Navigable Waters Protection Act, for construction in certain water courses that are navigable by watercraft. The Fisheries Act also prohibits the deposit of any deleterious substance into water frequented by fish unless otherwise authorized. Amendments to the Fisheries Act recently came into force in the late fall of 2013, such that the focus of the legislation is now on preservation of fish and fisheries, versus a previous focus on fish habitat.

Other federal legislation that our coal interests in Canada must comply with includes the Canadian Environmental Protection Act 1999, which, among other things, regulates the use, importing, storage and interprovincial or international transport of certain restricted and prohibited substances.

The Canadian Environmental Assessment Act, 2012 (“CEAA 2012”) requires that an environmental assessment be conducted with respect to certain designated types of projects such as the construction, operation, decommissioning or abandonment of certain coal and potash mines. The CEAA 2012 may apply to some of the proposed projects of the Corporation or its coal interests.

Although approvals under the Migratory Birds Convention Act, 1994 are not required, penalties under this statute can be imposed if activities result in harm to migratory birds. Federal legislation relating to the protection of endangered species has been enacted under the Species at Risk Act which could impact our ability to develop new mines in Canada or mine in certain areas, or which could require added expenses to preserve or enhance habitat for endangered species.

Environment Canada is in the process of a 10-year review of the Metal Mining Effluent Regulations (“MMER”) and is proposing to include coal interests in the regulations. The proposed MMER identify numerous new substance effluent limits and monitoring requirements. The potential impacts to our operations in Canada could include changes to effluent limits and increased monitoring and reporting requirements.

Representatives of the Canadian Council of Ministers of the Environment, and federal, provincial and territorial representatives have adopted the Air Quality Management System which includes Base Level Industrial Emission Requirements and an air zone management system. This has the potential to materially impact capital expenditures at our Canadian operations as equipment may need to be modified or replaced.

Greenhouse Gas Emission Reduction Frameworks. The most recent periodic conferences of the parties to the United Nations Framework Convention on Climate Change have not resulted in a legally binding agreement to succeed the Kyoto Protocol, the first commitment period of which ended at that end of 2012, and a second commitment period of which is from 2013 to 2020; in the meantime, an ad hoc working group was established to develop by no later than 2015 an acceptable protocol, legal instrument or an agreed outcome with legal force under the Convention, applicable to all parties, to come into effect and be implemented from 2020. In addition, a number of leading nations, including the United States, China, Brazil, and India, entered into a commitment referred to as the Copenhagen Accord which called on countries to voluntarily submit mitigation targets by January 31, 2010. In response, the current Canadian federal government has proposed to reduce its emissions by 17% below 2005 levels by 2020, which is consistent with targets currently being considered by the United States government. It is unclear at this time whether it will continue on a path forward to achieving these targets or whether it will re-evaluate its position.

On September 12, 2012, the Federal Government released the Canadian CO2 Regulations. The CO2 Regulations will require, among other things, that new and certain refurbished coal-fired plants, commissioned on or after July 1, 2015, achieve an annual average emissions intensity performance standard of 420 tonnes of CO2 per GWh. In general, for units commissioned prior to that date, the same standard would take effect between 45 and 50 years from the unit’s commissioning date. In practice, although there are certain temporary exceptions to the performance standard, the Canadian CO2 Regulations may result in certain coal-fired units retiring earlier than they would have otherwise. The Canadian CO2 Regulations could also have a significant effect on the customers of our Prairie operations, which in turn could, over time, significantly reduce the demand for the coal produced from our Prairie operations.

In addition, various Canadian provincial governments and other regional initiatives are moving ahead with GHG reduction and other initiatives designed to address climate change. In addition, various Canadian provincial governments and other regional initiatives are moving ahead with GHG reduction and other initiatives designed to address climate change. Under the Climate Change and Emissions Management Act (the “CCEM”), the Province of Alberta enacted the “Specified Gas Emitters Regulation.” As of January 1, 2008, this enactment requires certain existing facilities with direct emissions of 100,000 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 a new facility, the net emissions intensity limits are dependent on the number of years in which the new facility has been in commercial operation.

 

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Companies regulated by the Specified Gas Emitters Regulation are given options under the regulation to aid them in achieving the required reductions in emissions. These compliance options include using emission offsets, emission performance credits and fund credits (obtained by contributing money to the Climate Change and Emissions Management Fund) against their total emissions. For the 2011 compliance period, CVRI’s Coal Valley operations exceeded the 100,000 ton emissions threshold established under the Specified Gas Emitters Regulation. The Coal Valley operations did not achieve the required 12% reductions in emissions intensity. This is due primarily to long-haul distances and lower yield on coal production in 2011. As a result of failing to achieve the required emissions reduction in 2011, the Coal Valley mine was required to contribute 16,830 fund credits to the Climate Change and Emissions Management Fund at CAD $15/Credit, for a total contribution of CAD $252,450. According to Sherritt’s public filings, for the 2012 compliance period, the preliminary calculations indicate Coal Valley will be required to purchase approximately 27,065 tons of fund credits at a cost of approximately CAD $450,975. It is anticipated that for the next several years, emissions intensity at Coal Valley will increase as the distance between the coal being mined and the processing plant increases. However, continuing efficiency improvements may help Coal Valley achieve future compliance with the Specified Gas Emitters Regulation.

The Government of Alberta has also introduced a complementary Specified Gas Reporting Regulation, which came into force on October 20, 2004. This legislation requires all industrial emitters emitting 50,000 tons or more of CO2e to report their annual GHG emissions in accordance with the specified Gas Reporting Standard published by the Government of Alberta.

In Saskatchewan, Bill 126, The Management and Reduction of Greenhouse Gases Act, was passed in 2010 but is not yet proclaimed in force. The legislation provides a framework for the control of GHG emissions by regulated emitters and will be proclaimed once accompanying draft regulations are finalized. The draft regulations under this Act have set a provincial GHG emissions reduction target of 20% below the level of emissions in 2006 (or a three year average) by 2020. The standards will apply to a regulated facility (including the mining or processing of coal) emitting over 50,000 tons of CO2 in any year. For a facility that emits greater than 25,000 tons of CO2 in a year, a report to the minister must be submitted annually indicating the level of greenhouse gases generated by the facility. Facilities from one emitter are grouped together if the emission activity relates to the generation of thermal electric power or steam. A Baseline Emission Level (“BEL”) application is required within 180 days after the legislation is proclaimed. The BEL will determine the annual cap and carbon compliance payment for regulated facilities if GHG emissions exceed the cap. The first year of annual returns must be verified by an independent third party.

Other provinces also have been taking steps to regulate GHG emissions. For example, Quebec initiated a cap and trade program in 2011, and British Columbia has enacted a carbon tax program in 2008. Both programs remain in effect. These programs may signal a policy trend as jurisdictions across North America continue to consider measures to reduce GHG emissions

Land Tenure. Coal reserves and leases in Canada are generally under the jurisdiction of provincial governments. Coal producers in Canada gain access to their coal reserves in one of three ways: Crown coal leases; freehold ownership; or third party leases or subleases. Royalty payments may be paid regardless of the method of ownership.

In Alberta, Crown coal leases are granted under the Mines and Minerals Act (Alberta) for terms of 15 years. The leases are renewable for further terms of 15 years each, subject to the Mines and Minerals Act (Alberta) and the regulations in force at the time of renewal, and, in the case of any particular renewal, to any terms and conditions prescribed by order of the Minister of Energy, unless relating to exploration where the terms and conditions may be prescribed by either the Ministry of Energy or the Minister of Sustainable Resource Development. New Crown coal leases on lands classified in Category 4 of ‘‘A Coal Development Policy for Alberta, 1976’’ are made available to the public through a competitive bidding process. Subbituminous coal obtained from Crown coal lease land that is used in electric power generation in Alberta is subject to a flat royalty rate currently set at $0.55 per tonne. For bituminous coal, royalty fees payable are based on a two-tiered system, with an initial rate of 1% payable on the mine-mouth value of marketable coal, and, once the cumulative payments under this first tier equal or exceed the aggregate of the allowed cumulative project costs and the cumulative return allowance of the project, an additional annual royalty of 13% on the Crown’s share of the mine’s total net revenue. Coal produced from lands leased from private owners may also be subject to private royalties pursuant to agreements. No provincial royalties are payable on production of coal from freehold rights.

In Saskatchewan, Crown coal leases are granted under The Crown Minerals Act and The Coal Disposition Regulations, 1988, for terms of 15 years. The leases are renewable for further terms of 15 years each, subject to The Crown Minerals Act and the regulations in force at the time of renewal. The Saskatchewan Ministry of the Economy will also assess the exploration operations that have previously been conducted on the applicable Crown lands. The Ministry has a policy that at least $40,000 worth of approved exploration expenditures are required before a permit may be converted to lease.

Prior to obtaining a Crown coal lease in Saskatchewan, the applicant typically first obtains a permit to explore the Crown lands.

 

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The application for this exploration permit must include details of the exploration operations and expenditures the applicant intends to carry out on the proposed permit lands. Under The Coal Disposition Regulations, 1988, the term of an exploration permit is three years and may be extended for two further terms of not more than six months each. The Ministry has a policy that at least $20,000 worth of approved exploration expenditures are required, in relation to each of the two potential permit extension periods, before a permit holder may qualify for the extensions.

Prior to the expiry of an exploration permit term or extension thereof, the holder of the exploration permit may apply to convert all or part of the permit lands into a lease or leases. There is no competitive bidding process for Saskatchewan Crown coal rights.

In Saskatchewan, the sale of coal from Crown coal leases is subject to payment of a Crown royalty in the amount of 15% of the mine-mouth value of coal related to the Crown lease. Crown royalties are payable quarterly pursuant to The Crown Coal Royalty Schedule to The Coal Disposition Regulations, 1988. Under The Mineral Taxation Act, 1983, there are two taxes levied against freehold coal rights and production. One is a freehold mineral tax, payable annually, of $960 per nominal section (or a pro rata amount for any area that is not a full nominal section) on the aggregate area of all mineral rights owned. The other is a freehold coal production tax, payable quarterly, of 7% on the mine-mouth value of coal related to the freehold land, which rate is set out in The Freehold Coal Production Tax Regulations.

Mine Permitting. To develop or extend an existing coal property, it is necessary to obtain a mine permit from the applicable provincial government.

In certain instances, such as when mine operations cross navigable waters or interfere with a fishery, it may be necessary to obtain permits from the federal government in Canada. The process of obtaining these permits involves disclosure of the project to the applicable authorities and typically requires the completion of an environmental impact assessment (“EIA”). The proposed components of an EIA are typically published for public input and with such input the procedures and studies to be included in the EIA are finalized.

To complete an EIA, full details of the proposed project are documented. The authorities review the EIA again with public input, and following required amendments or additions the EIA is deemed complete. Depending on the magnitude of the project, the level of public interest, and the location of the project, the regulators may also require a public hearing process. When this process is complete the regulators will approve the project, request modifications to the project and approve it as modified, or reject the project. Once an EIA is approved the required permits can be issued.

If both the federal and provincial governments are involved, the application is subject to joint review. For a greenfield project the permitting process can take three to five years. For a mine-extension project the permitting process has, in the past, only taken about two years, but recent changes in the structure of regulatory bodies’ decision making process, and increased aboriginal consultation expectations may lead to longer application times that has been experienced in the past.

The Coal Conservation Act (Alberta) (“CCA”) applies to every mine, coal processing plant and in situ coal scheme in Alberta as well as to all coal produced and transported in Alberta. The CCA requires a permit to explore for coal and to develop a mine site or mine, and requires a license to begin mining operations at a site at which mining operations have not previously been undertaken or at an abandoned mine. The CCA sets out separate requirements for approvals and licenses for in situ coal schemes. A license is also required to resume operations at a mine that has suspended operations for longer than 12 months. Applications for both a permit and license are made to the Alberta Energy Regulator (“AER”). The AER may grant a permit or a license where it is in the public interest to do so having regard to the present and future requirements for coal in Alberta, and subject to any conditions, restrictions or stipulations it considers appropriate set out in the permit, licence, approval or amendment. The AER may also require a performance bond to be posted to ensure compliance with the CCA. In addition, a separate performance bond may be required for each mine or processing plant located on one development.

Municipal By-laws. Coal operations are also subject to local laws, including by-laws passed by local municipalities relating to land use, rural road closures, storm run-off and nuisance situations, such as dust and weed controls.

Canadian Electric Utility Industry. The electric utility industry in Canada is subject to extensive regulation regarding the environmental impact of electricity generation activities. New legislation or regulations could be adopted that may have a significant impact on coal mining operations or the ability of coal customers to use coal. Future legislation and regulations could cause additional expense, capital expenditures, reclamation obligations, restrictions and delays in the development of new coal mines or the operation of existing coal mines, the extent of which cannot be predicted. In the context of environmental permitting, including the approval of reclamation plans, our coal interests in Canada must comply with legislated or regulated standards and existing laws and regulations which may entail greater or lesser costs and delays depending on the nature of the activity to be permitted and how stringently the regulations are implemented by the permitting authority.

 

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Competition

While the coal industry is intensely competitive, we focus on niche coal markets where we take advantage of long-term coal contracts with neighboring power plants. For our open market coal sales, we compete with many other suppliers of coal to provide fuel to power plants. Additionally, coal producers compete with producers of alternative fuels used for electrical power generation, such as nuclear energy, natural gas, hydropower, petroleum and wind. Costs and other factors such as safety, environmental and regulatory considerations relating to these alternative fuels affect the overall demand for coal as a fuel.

We believe that our mines have a competitive advantage based on three factors: a

 

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all of our mines are the most economic suppliers to each of their respective principal customers, as a result of transportation advantages over our competitors in each of our key markets;

 

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nearly all of the power plants we supply were specifically designed to use our coal; and

 

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the plants we supply are among the lowest cost producers of electric power in their respective regions and are among the cleaner producers of power from solid fossil fuels.

Because of the foregoing, we believe that our current customers are more likely to be dispatched to produce power and to continue purchasing coal extracted from our mines.

The Absaloka Mine and the Coal Valley Mine face a different competitive situation. The Absaloka Mine sells its coal in the rail market to utilities located in the northern tier of the United States served by BNSF and a majority of coal from the Mountain Operations is sold on the international market to overseas customers. Customers of these mines may purchase coal from us or from other producers. We compete with other producers based on price and quality, with the purchasers also taking into account the cost of transporting the coal to their plants. The Absaloka Mine enjoys an over 300-mile rail advantage over its principal competitors from the Southern Powder River Basin in supplying customers located in the northern tier and the Mountain Operations enjoy fixed available port capacity. Rail rates have increased over the last several years by 50 to 100%, which strengthens our competitive advantage.

Seasonality

Our coal business has historically experienced only limited variability in its results due to the effect of seasons; however, we are impacted by seasonality due to weather patterns and our customer’s annual maintenance outages which typically occur during the second quarter. In addition, our customers generally respond to seasonal variations in electricity demand based upon the number of heating degree days and cooling degree days. Due to stockpile management by our customers, our coal sales may not experience the same direct seasonal volatility; however, extended mild weather patterns can impact the demand for our coal. Our sales typically benefit from decreases in customers’ stockpiles due to high electricity demand. Conversely, when these stockpiles increase, demand for our coal will typically soften. Further, our ability to deliver coal is impacted by the seasons. Because the majority of our mines are mine-mouth operations that deliver their coal production to adjacent power plants, our exposure to transportation delays our outages as a result of adverse weather conditions is limited.

Employees and Labor Relations

We have almost 2,900 employees on a pro forma basis. Approximately 64% of our employees are represented by collective bargaining agreements. At our United States mines, we have labor agreements in place at each of the Savage Mine, Rosebud Mine and Kemmerer Mine, which were renegotiated in 2012 and expire in 2016, 2018 and 2019, respectively. We also have labor agreements at our Beulah and Absaloka Mines, which expire in 2014 and 2015, respectively. We believe that we have good relations with our represented employees.

The workforce at our Canadian mines is also largely unionized and will increase the percentage of our workforce represented by a labor union. There are labor agreements in place at each of the producing Sherritt mines we are acquiring other than the Genesee mine. The workforce at these mines is represented by four unions, the Union of Operating Engineers Local 400 and Local 955, the UMWA Local 7606, the International Brotherhood of Electrical Workers, Local 2067 and the Communications, Energy and Paperworkers Union of Canada, Local 649. The agreement at the Poplar River Mine with the International Brotherhood of Electrical Workers, Local 2067 expired in November of 2013. A memorandum of understanding for a new agreement was signed on January 9, 2014, and Sherritt management anticipates approval of the new agreement in early February. The agreement at the Coal Valley mine with the Union of Operating Engineers Local 955 expires on February 28, 2014, and negotiations with the Union were scheduled to begin in mid-January. The remainder of the labor agreements applicable to the Sherritt subsidiaries will expire between 2015 and 2018. We believe Sherritt has historically had good relations with its unionized employees and representative unions.

 

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