ITEM 1
- BUSINESS.
Overview
Westmoreland Coal Company began mining in Westmoreland County, Pennsylvania in 1854 as a Pennsylvania corporation. In 1910, we incorporated in Delaware and continued our focus on coal operations in Pennsylvania and the Appalachian Basin. We moved our headquarters from Philadelphia, Pennsylvania to Colorado Springs in 1995 and relocated the headquarters to Englewood, Colorado in November 2011.
Today, Westmoreland Coal Company is an energy company employing approximately 3,248 employees. We conduct our operations through our subsidiaries and our principal sources of cash are distributions from our operating subsidiaries. At December 31, 2015, our operations included 12 wholly-owned coal mines in the U.S. and Canada, a char production facility, a 50% stake in an activated carbon plant, and two coal-fired power generation units. We also own the general partner of, and 93.8% of the total equity interest in,WMLP, which is a publicly traded limited partnership that owns and operates five mining complexes in Ohio and one mine in Wyoming. We sold 53.3 million tons of coal in 2015.
We classify our business into six segments: Coal - U.S., Coal - Canada, Coal - WMLP, Power, Heritage, and Corporate. Our principal operating segments are our Coal - U.S., Coal - Canada, Coal - WMLP and Power segments. Our two non-operating segments are our Heritage and Corporate segments. Our Heritage segment primarily includes the costs of benefits we provide to former mining operation employees, and our Corporate segment consists primarily of corporate administrative expenses and business development expenses. In addition, the Corporate segment contains our captive insurance company, Westmoreland Risk Management Inc. (“WRM”), through which we have elected to retain some of our operating risks.
We produce and sell thermal coal primarily to investment grade utility customers under long-term cost-protected contracts, as well as to industrial customers and barbeque briquettes manufacturers. With the exception of the San Juan mine and the Buckingham mine, each of which are underground mines, our focus is on mine locations where we can employ dragline surface mining methods. We have extensive operational experience in dragline surface mining and this mining method has historically had predictable and consistent costs and production rates. In addition, we focus on mine locations that allow us to take advantage of close customer proximity through mine-mouth power plants and strategically located rail transportation, with the goal of being the low-cost supplier of choice to the customers that we serve. We believe this business model has contributed to the stability of our cash flows and results of operations.
At December 31, 2015, our U.S. coal operations were located in Montana, North Dakota, Texas and Ohio. Following the San Juan Acquisition in January of 2016, we expanded our U.S. coal operations to include New Mexico. Our Canadian coal operations are located in Alberta and Saskatchewan. Our WMLP coal operations are in Ohio and Wyoming. We also operate two coal-fired power generating units in North Carolina with a total capacity of approximately 230 megawatts.
The following chart provides an overview of the current operating subsidiaries that compose our coal and power segments and our relationship to each of them as of the filing date of this report, unless otherwise noted. The entities shaded in dark grey represent the “Restricted Group”, and the unshaded entities represent the “Unrestricted Group” for the purposes of certain of our debt agreements and instruments, described in further detail in Item 7 - Management’s Discussion and Analysis of Financial Condition and Results of Operations and also at Note 8 - Lines Of Credit And Long-Term Debt to our consolidated financial statements:
(1) The San Juan Acquisition closed on January 31, 2016
(2) As of January 1, 2016 Coal Valley Resources Inc. was amalgamated with Prairie Mines & Royalty ULC
(3) As WMLP's general partner, we are entitled to incentive distribution rights (IDR)
As of December 31, 2015, our long-term debt consisted of (i) $350 million in principal amount of our 8.75% senior secured notes due 2022 (“8.75% Notes” or “Indenture”) and (ii) a $327 million principal balance on our term loan maturing in 2020 (“WCC Term Loan Facility”). Additionally, availability under the our revolving line of credit (“WCC Revolving Credit Facility”) was $28.2 million with an outstanding balance of $19.8 million supporting letters of credit and $2.0 million drawn on the WCC Revolving Credit Facility. Refer to the information regarding the revenues, operating income and total assets of each of our segments for the years ended December 31, 2015, 2014 and 2013 contained in Note 19 - Business Segment Information to our consolidated financial statements.
Debt Facility
WMLP has a $295 million credit facility (the “WMLP Term Loan Facility”) that is governed by a Financing Agreement among Oxford Mining Company, LLC (“Oxford”), WMLP and certain of its subsidiaries as guarantors, the lenders party thereto and U.S. Bank National Association as administrative and collateral agent (the “WMLP Financing Agreement”). The WMLP Term Loan Facility consists of an initial $175 million term loan and an option for an additional $120 million in term loans for acquisitions which was exercised on August 1, 2015 to finance the Kemmerer Drop. The WMLP Term Loan Facility matures in December 2018 and the WMLP Financing Agreement contains customary financial and other covenants. It also permits distributions to WMLP’s unitholders under specified circumstances. Borrowings under the WMLP Financing Agreement are secured by substantially all of WMLP’s and its subsidiaries’ assets.
2015 Transactions
Buckingham Acquisition
On January 1, 2015, we acquired Buckingham Coal Company, LLC (“Buckingham”), an Ohio-based coal supplier, for a total cash purchase price of $32.5 million. Separately, an affiliate of Westmoreland entered into a five-year coal supply agreement with AEP Generation Resources Inc. (“AEP”), which includes an obligation to purchase a minimum of 5.5 million tons of coal. In connection with this acquisition, we amended the WCC Term Loan Facility to increase the principal amount by $75.0 million, for an aggregate principal WCC Term Loan Facility amount of $425 million as of January 22, 2015.
Buckingham conducts underground room and pillar mining operations in Ohio. Buckingham is strategically located near WMLP's New Lexington complex, which has access to the Norfolk Southern rail system and a state-of-the-art preparation plant strategically located for efficient rail and river transportation for both Buckingham and WMLP coal. We expect Buckingham's proximity to WMLP’s New Lexington complex to allow for substitute tonnage to be supplied by WMLP to AEP when it is economically advantageous to do so.
Kemmerer Drop
Effective August 1, 2015, we contributed 100% of the outstanding equity interests in Westmoreland Kemmerer, LLC (“Kemmerer”), which owns and operates the Kemmerer Mine in Lincoln County, Wyoming, to WMLP in exchange for $230 million in aggregate consideration, composed of $115 million of cash and $115 million in newly issued WMLP Series A Convertible Units (the “Series A Units” and such transaction, the “Kemmerer Drop”). In connection with the Kemmerer Drop, all employees of Kemmerer and related employee liabilities, including but not limited to post-retirement pension obligations and post-retirement health benefits, were transferred to us.The Series A Units are convertible into common units representing limited partner interests of WMLP (“Common Units”), on a one-for-one basis, upon the earlier of (i) the date on which WMLP first makes a regular quarterly cash distribution to holders of Common Units in an amount equal to at least $0.22 per Common Unit, or (ii) a change of control of WMLP. Following the Kemmerer Drop, we hold a 93.8% interest in WMLP (on a fully diluted basis).
WCC Revolving Credit Facility Amendment
On June 2, 2015, we amended the WCC Revolving Credit Facility to permit Westmoreland and the other U.S. borrowers thereunder to borrow up to an additional $25.0 million between June 15th and August 15th of each year. As a result, the U.S. sub-facility has a maximum available borrowing amount of $55.0 million during these periods, and the Canadian sub-facility has a maximum available borrowing amount of $20.0 million yielding a total aggregate borrowing capacity of $75.0 million. Outside of these periods, the WCC Revolving Credit Facility has a maximum available borrowing amount of $50.0 million.
WMLP Revolving Credit Facility
On October 23, 2015, WMLP and its subsidiaries entered into a revolving credit facility with the lenders party thereto and The PrivateBank and Trust Company, as administrative agent (the “WMLP Revolving Credit Facility”). The WMLP Revolving Credit Facility permits borrowings up to the aggregate principal amount of $15.0 million and permits letters of credit in an aggregate outstanding amount of up to $10.0 million, which reduces availability under the WMLP Revolving Credit Facility on a dollar-for-dollar basis. At December 31, 2015, availability under the WMLP Revolving Credit Facility was $15.0 million with no outstanding balance or supporting letters of credit.
Recent Developments
On January 31, 2016, Westmoreland San Juan, LLC (“WSJ”), a special purpose subsidiary of Westmoreland, acquired San Juan Coal Company (“SJCC”), which operates the San Juan mine in Farmington, New Mexico, and San Juan Transportation Company (together with SJCC, the “San Juan Entities” and such transaction, the “San Juan Acquisition”) for a total cash purchase price of approximately $127 million, subject to post-closing adjustments. The San Juan mine is the exclusive supplier of coal to the adjacent San Juan Generating Station (“SJGS”) under a coal supply agreement with tonnage and pricing adjusting quarterly through 2022.
WSJ financed the San Juan Acquisition with a $125 million loan from NM Capital Utility Corporation, an affiliate of Public Service Company of New Mexico (one of the owners of SJGS), and with available cash on hand. The loan is structured as a senior secured term loan (the “San Juan Loan”) maturing February 1, 2021 and is expected to bear interest at a (i) 7.25% rate (the “Margin Rate”) plus (ii) (A) the London Interbank Offered Rate for a three month period plus (B) a statutory reserve rate, which such Margin Rate increases incrementally during each year of the Loan term. The Loan has no prepayment penalties. The agreements governing the Loan include representations and warranties and covenants regarding the ownership and operation of SJCC and the properties acquired in the Acquisition and standard special purpose bankruptcy remote entity covenants designed to preserve the separateness from Westmoreland of each of (i) WSJ, (ii) its direct parent company, Westmoreland San Juan Holdings, Inc., and (iii) the San Juan Entities ((i), (ii) and (iii) collectively, the “Westmoreland San Juan Entities”). Obligations under the Loan are recourse only to the Westmoreland San Juan Entities and their assets and neither Westmoreland nor its subsidiaries (other than the Westmoreland San Juan Entities) is an obligor under the Loan in any respect. The agreement governing the Loan requires that all revenues of the San Juan Entities, aside from payments on certain leases, are deposited into a cash management collection account swept monthly for operating expenses, capital expenditures, and Loan payment and prepayment.
In connection with certain mining permits relating to the operation of the San Juan mine, WSJ is required to post reclamation bonds of $162 million with the New Mexico Mining and Minerals Division. In order to facilitate the posting of reclamation bonds by Zurich American Insurance Company (“Zurich”) on behalf of WSJ, PNM Resources, Inc. (“PNM”), Westmoreland and SJCC entered into a Reclamation Bond Agreement (the “Reclamation Bond Agreement”) with Zurich.
The following map shows our operations, as of the date of this filing, including the operations under our control following the San Juan Acquisition:
Coal Segments
General
Our Coal - U.S. and Coal - Canada Segments focus on niche coal markets where we take advantage of customer proximity and strategically located rail transportation. We sell substantially all of the coal that we produce to power generation facilities. The close proximity of our mines and coal reserves to our customers reduces transportation costs and, we believe, provides us with a significant competitive advantage with respect to retention of those customers. Ten of our 12 mines are in very close proximity to the customer’s property, with economical delivery methods that include, in several cases, conveyor belt delivery systems linked to the customer’s facilities. We typically enter into long-term, cost-protected supply contracts with our customers that range from approximately one to 40 years. Our current coal sales contracts have a weighted average remaining term of 15 years. For the twelve months ended December 31, 2015, substantially all of our tons of coal sold were sold under long-term contracts. We employ a rigorous capital spending and maintenance philosophy and believe our equipment is well maintained.
Properties
Across all our coal operating segments (Coal - U.S., Coal - Canada and Coal - WMLP), we owned or controlled an estimated 1,222 million tons of total proven or probable coal reserves as of December 31, 2015, including 145 million tons of proven or probable coal reserves held by WMLP.
Substantially all of our properties and assets in the Coal - U.S. Segment and Coal - Canada Segment are encumbered by liens securing our and our subsidiaries’ outstanding indebtedness. Specifically, the holders of the 8.75% Notes and the lenders under the WCC Term Loan Facility hold first priority liens, on a pari passu basis, on substantially all of our and our wholly owned subsidiaries’ tangible and intangible assets (excluding certain equity interests, mineral rights and sales contracts and certain assets subject to existing liens). In addition, borrowings under the WCC Revolving Credit Facility are secured by first priority liens on our and our wholly owned subsidiaries accounts receivable, inventory and certain other specified assets. The assets of WMLP are encumbered by separate liens securing the indebtedness of WMLP and its subsidiaries and are not part of the collateral with respect to the 8.75% Notes, the WCC Term Loan Facility or the WCC Revolving Credit Facility.
The following table provides information about mines we owned or controlled as of December 31, 2015:
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(1)
The SEC Industry Guide 7 defines reserves as that part of a mineral deposit, which could be economically and legally extracted or produced at the time of the reserve determination. Proven and probable coal reserves are defined by SEC Industry Guide 7 as follows:
Proven (Measured) Reserves - Reserves for which (a) quantity is computed from dimensions revealed in outcrops, trenches, workings or drill holes; grade and/or quality are computed from the results of detailed sampling and (b) the sites for inspection, sampling and measurement are spaced so close and the geographic character is so well defined that size, shape, depth and mineral content of reserves are well-established.
Probable (Indicated) Reserves - Reserves for which quantity and grade and/or quality are computed from information similar to that used for proven (measured) reserves, but the sites for inspection, sampling and measurement are farther apart or are otherwise less adequately spaced. The degree of assurance, although lower than that for proven (measured) reserves, is high enough to assume continuity between points of observation.
(2)
Represents total reserve information for WMLP, of which we are the general partner and owner of 93.8% of the total outstanding equity interests.
The following table provides summary information regarding our principal mining operations as of December 31, 2015:
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(1)
The total number of employees for the Ohio - Oxford mining complexes does not include 39 non-union employees located at administrative offices nor does it include 76 non-union employees located at mine support facilities.
(2)
WCC acquired the GP of WMLP on December 31, 2014, therefore, historical tonnage for 2013 is not applicable to the Ohio - Oxford mines.
(3)
The Tusky, Plainfield and Muhlenberg mine complexes were inactive during 2015, therefore, their individual statistics are not presented.
(4)
As the Oxford mining complexes sell their coal from centralized coal pits, breaking tons sold and PP&E out by mine is not meaningful. Therefore, the table above shows the Ohio - Oxford mine's tons sold and PP&E in total.
(5)
The labor agreement at the Kemmerer Mine expires in 2018.
Coal - U.S. Segment Properties
Our Coal - U.S. Segment is composed of our wholly owned mines located in the United States. Mines in our Coal - U.S. Segment control coal reserves and deposits through long-term leases. Our Coal - U.S. Segment owned or controlled an estimated 376.1 million tons of total proven or probable coal reserves as of December 31, 2015. Montana, Texas, and North Dakota each use a permitting process approved by the Office of Surface Mining. Mines in our Coal - U.S. Segment have chosen to permit coal reserves on an incremental basis and given the current rates of mining and demand, have sufficient permitted coal to meet production for the periods shown in the table below. We secure all of our final reclamation obligations by reclamation bonds as required by the respective state agencies. We perform contemporaneous reclamation activities at each mine in the normal course of operations and coal production.
The following table provides information about mines in our Coal - U.S. Segment as of December 31, 2015:
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(1)
Approximate year in which permitted reserves would be exhausted, based on current mine plan and production rates. The Jewett Mine’s reserves are covered under two separate mining permits, which must be renewed every five years.
(2)
Approximate heat content applies to the coal mined in 2015.
(3)
Approximate sulfur content applies to the tons mined in 2015.
With the exception of the Jewett mine, where we control some reserves through fee ownership, we lease all of our coal properties in our Coal - U.S. Segment. We are a party to coal leases with the federal government, state governments, and private parties at our Absaloka, Colstrip, Beulah, Savage and Jewett Mines. Each of the federal and state government leases continue indefinitely provided there is diligent development of the property and continued operation of the related mines. Federal statute generally sets production royalties on federal leases at 12.5% of the gross proceeds of coal mined and sold for surface mines. Our private leases are generally long-term and have options for renewal. We believe that we have satisfied all lease conditions in order to retain the properties and keep the leases in place.
We are a party to two leases with the Crow Tribe covering 18,406 acres of land at our Absaloka Mine, which are held by our wholly owned subsidiary, Westmoreland Resources, Inc. (“WRI”). In 2008, and in order to take advantage of certain
Indian Coal Tax Credits (“ICTC”) for the production of coal on the leased Crow Tribe land, WRI entered into a series of transactions, including the formation of Absaloka Coal, LLC with an unaffiliated partner. As part of such transaction, WRI subleased its leases with the Crow Tribe to Absaloka Coal, LLC, granting it the right to mine specified quantities of coal with WRI as contract miner. From 2009 through 2013, we experienced a yearly average of $3.1 million of income and $6.1 million of cash receipts from the ICTC. On December 18, 2015, the ICTC was extended for two years through December 31, 2016 as part of H.R. 2029 - the Consolidated Appropriations Act 2016. We plan to pursue monetization of this tax credit in the future if possible.
Coal - Canada Segment Properties
Mines in our Coal - Canada Segment owned or controlled an estimated 700.7 million tons of total proven or probable coal reserves as of December 31, 2015. In 2015 we conducted our Canadian coal operations through Coal Valley Resources Inc. which operated our Coal Valley Mine and Prairie Mines & Royalty ULC which operated the mines comprising our Prairie Operations. On January 1, 2016 Coal Valley Resources Inc. and Prairie Mines & Royalty ULC were amalgamated with the resulting entity continuing under the name Prairie Mines & Royalty ULC. Mines in our Coal - Canada Segment control coal reserves and deposits through a combination of long-term Crown or third-party leases or through fee ownership. The majority of our Prairie Operation’s coal production is sold to Canadian utilities for electricity production, and all of our Prairie Operation’s five mines are mine mouth operations (where our mine is adjacent to the customer’s plant). The Coal Valley Mine produces thermal coal which is exported primarily to the Asia-Pacific market via rail and ocean vessel under reserved port capacity. Our Canadian operations are located in Alberta and Saskatchewan and our mines are permitted in accordance with the legislation in effect in those Provinces. We secure all of our final reclamation obligations by reclamation bonds as required by the respective provincial agencies. We perform contemporaneous reclamation activities at each mine in the normal course of operations and coal production.
The following table provides information about mines in our Coal - Canada Segment as of December 31, 2015:
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(1)
Approximate year in which permitted reserves would be exhausted, based on current mine plan and production rates.
(2)
Approximate heat content applies to the coal mined in 2015.
(3)
Approximate sulfur content applies to the coal mined in 2015.
Coal reserves and leases in Canada are generally under the jurisdiction of provincial governments. Coal producers, including Westmoreland, gain access to their coal reserves through provincial Crown coal leases, freehold ownership or third party leases or subleases. Coal reserves for our Canadian Operations are held by all three methods, the mix of which varies from mine to mine.
Alberta Crown coal leases are granted under the Mines and Minerals Act (Alberta) for terms of 15 years. The leases are renewable for further terms of 15 years each, subject to the Mines and Minerals Act (Alberta) and the regulations in force at the time of renewal, and, in the case of any particular renewal, to any terms and conditions prescribed by order of the Minister of Energy. Crown coal royalties are set by the Coal Royalty Regulation (Alberta). Under this regulation, there are two royalty regimes. The royalty rate for Crown-owned sub-bituminous coal is $0.55 per tonne, which is roughly equivalent to $0.50 per ton. The royalty rate for Crown-owned bituminous coal, which is based on a revenue less cost regime, is 1% of mine mouth revenue prior to mine payout, plus an additional 13% of net revenue after mine payout. No provincial royalties or mineral taxes are payable on freehold coal.
Saskatchewan Crown coal leases are granted under The Crown Minerals Act and The Coal Disposition Regulations, 1988, for terms of 15 years. The leases are renewable for further terms of 15 years each, subject to The Crown Minerals Act and the regulations in force at the time of renewal. In Saskatchewan, Crown royalties in the amount of 15% of the mine-mouth value of coal are payable quarterly pursuant to The Crown Coal Royalty Schedule to The Coal Disposition Regulations, 1988. The Mineral Taxation Act, 1983, levies two taxes against freehold coal rights and production. One is an annual freehold mineral tax of $960 per nominal section. The other is a freehold coal production tax, payable quarterly, of 7% on the mine mouth value of coal.
We believe that we have satisfied all lease conditions in order to retain the properties and keep the leases in place.
Coal - U.S. and Coal - Canada Segment Customers
U.S. Coal Segment
In 2015, our Coal - U.S. Segment derived approximately 75% of its total revenues from coal sales to five power plants: Colstrip Units 3&4 (26%); Limestone Generating Station (16%); American Electric Power Company, Inc. (13%), Colstrip Units 1&2 (11%); and Pacificorp Energy, Inc. (9%). We sell the majority of our tons under contracts with remaining supply obligation terms of three years or more. We provide coal delivery via conveyor belt to our mine-mouth customers, and also sell coal and lignite on a Freight On Board, or FOB, basis to our other customers. The purchaser of coal normally bears the cost of transportation and risk of loss from load-out to its final destination.
Colstrip. The Colstrip Mine has two long-term, cost-plus contracts with the adjacent Colstrip Station power generating facility. The supply agreement for Colstrip Units 1 and 2 has a projected term through 2022 and expected tons of 2.3 million annually. A second agreement for Colstrip Units 3 and 4 provides for approximately 6.3 million tons per year and is set to expire at the end of 2019. The agreement related to Units 3 and 4 also has provisions for specific returns on capital investments.
Absaloka. The Absaloka Mine operates primarily in the open market and has several two- to eleven-year contracts with various parties. The capacity of the mine ranges between 5.5 million and 7.4 million tons annually. In 2013 and 2014, the Absaloka Mine sold 4.2 million and 6.6 million tons, respectively. The low annual sales in 2013 relative to mine capacity was due to an extended outage of the Sherburne County Generating Station in Becker, Minnesota, which is the mine’s largest customer. In 2015, the Absaloka Mine sold 5.8 million tons. Burlington Northern Santa Fe provides rail service to the mine, which also has the ability to load and ship coal via over-the-road trucks. Prices under these agreements are based upon certain actual mine costs and certain inflation indices for such items as diesel fuel. In October 2015, Xcel Energy, the owner of the Sherburne County Generating Station, announced a plan to retire Units 1 and 2 of the plant’s three generating units in 2026 and 2023, respectively.
Savage. The Savage Mine supplies approximately 0.3 million tons annually to the Lewis & Clark Power Station and Sidney Sugars Incorporated. Both customers are located within close proximity to the mine and coal deliveries are provided via over-the-road truck. The mine entered into new agreements with both customers in 2012 that both expire in December 2017. Prices under these agreements are based on certain actual mine costs, commodity indices (for items such as diesel fuel), and the agreements contain provisions for capital recovery.
Jewett. The Jewett Mine has a cost-plus agreement with NRG Texas Power’s adjacent Limestone Generating Station. NRG Texas Power is also responsible for the mine’s capital and reclamation expenditures. The agreement has a term through 2018, which may be extended by NRG Texas Power for up to an additional ten years or until the mine’s reserves are exhausted. NRG has the option to determine volumes to be delivered, which average between four and five million tons annually. NRG may terminate the agreement at its discretion.
Beulah. The Beulah Mine supplies approximately 2.5 million tons annually to the adjacent Coyote Electric Generating Plant via conveyor belt under an agreement that expires in May 2016. The Coyote agreement has provisions for specific returns on capital investment. We have received notice that the Coyote Electric Generating Plant will not be renewing its contract past 2016. The Beulah Mine also supplies approximately 0.5 million tons annually via rail to the Heskett Power Station under an agreement that expires in 2021. Prices under these agreements are based upon certain actual mine costs and certain inflation/commodity indices for items such as diesel fuel.
Buckingham. The Buckingham Mine conducts underground room and pillar mining operations in Ohio. Buckingham is strategically located near WMLP’s New Lexington complex, which has access to the Norfolk Southern rail system and a state-of-the-art preparation plant strategically located for efficient rail and river transportation for both Buckingham and WMLP coal. The Buckingham Mine supplies coal to AEP under a five-year coal supply agreement that includes an obligation to purchase a minimum of 5.5 million tons of coal. Buckingham’s proximity to WMLP’s New Lexington complex allows us to substitute tonnage to be supplied by WMLP to AEP when it is economically advantageous to do so.
Coal - Canada Segment Customers
Our Coal - Canada Segment sells the majority of its tons under contracts with remaining supply obligation terms of between one and 40 years. In 2015 our Coal - Canada Segment derived approximately 80% of its total revenues from coal sales to two customers and one country: SaskPower (42%), the country of Japan (22%) and ATCO Power (17%). The majority of our Prairie Operation’s coal production is sold to Canadian utilities for electricity production, and all of our Prairie Operation’s five mines are mine mouth operations. The Coal Valley Mine produces thermal coal which is exported primarily to the Asia-Pacific market via rail and ocean vessel under reserved port capacity.
Paintearth. The Paintearth Mine is a surface mine located in Central Alberta south of the Village of Forestburg. The mine operates two active pits and supplies sub-bituminous coal to the four generating units at the Battle River Generating Station which are owned and operated by Alberta Power (2000) Ltd. (“ATCO Power"). Current annual production of the mine is 1.5 million tons. The coal supply contract for the mine expires in 2022.
Sheerness. The Sheerness Mine is a surface mine located in South Central Alberta south of the Town of Hanna. The mine operates two active pits and supplies sub-bituminous coal to the two generating units at the Sheerness Generating Station which is owned by TransAlta Corporation and ATCO Power and operated by ATCO Power. Current annual production of the mine is 3.6 million tons. The current coal supply contract for the mine expires in 2026.
Poplar River. The Poplar River Mine is a surface mine located in South Central Saskatchewan near the Town of Coronach. The mine operates two active pits and supplies lignite coal to the two generating units at the Poplar River Generating Station which is owned and operated by Saskatchewan Power Corporation (“SaskPower”). Current annual production of the mine is 4.1 million tons. The coal supply contract for the mine expires in 2029. The Poplar River Mine owns and operates the railway from the mine to the generating station.
Estevan. The Estevan Mine combines two of our adjacent mines in southeastern Saskatchewan, the Bienfait Mine and the Boundary Dam Mine, which supply an approximate combined 6.4 million tons per year to SaskPower, domestic consumers and the char and activated carbon plants. Our contract with SaskPower related to the Estevan Mine is through 2024. The Estevan Mine operates four active pits and supplies lignite coal to the Boundary Dam Generating Station (4 Units) (“Boundary Dam”), the Shand Generating Station (1 Unit) (“Shand”), the activated carbon plant, the char plant, as well as some domestic sales. SaskPower has constructed and commissioned a carbon dioxide capture and sequestration (“CCS”) facility at Boundary Dam and a carbon capture test facility at Shand. This combined project is the largest commercial scale CCS facility in the world, and is funded by the government of Saskatchewan with backing from the Canadian government, and, should mitigate the impact of Canadian GHG regulations on Boundary Dam.
Genesee. The Genesee Mine is a surface mine located in central Alberta north of the Town of Warburg and close to Edmonton. The mine operates two active pits and supplies sub-bituminous coal to the three units at the Genesee Generating Station which are owned by Capital Power and TransAlta Corporation and operated by Capital Power. The Genesee Mine, which is a joint venture between Capital Power and Westmoreland, supplies approximately 5.7 million tons per year to Capital Power and the contract runs for the life of the mine.
Coal Valley. The Coal Valley Mine is a surface mine located in west central Alberta south of the Town of Edson. The mine operates both truck/shovel and dragline pits and utilizes a dragline for coal removal. The mine exports high quality sub-bituminous coal to customers in the Asia-Pacific market as well as supplying some domestic customers. Current annual clean production of the mine is 2.1 million tons and the plant has capacity to operate at approximately 4.0 million tons per year.
Activated Carbon Plant. A 50/50 joint venture with Cabot Corporation, the plant was initially commissioned in June 2010. The activated carbon plant is located at the Estevan Mine and the activated carbon produced is sold to coal-fired power producers for the purpose of mercury removal from flue gas emitted to the atmosphere. Regulations regarding mercury emissions have significantly increased demand for this product.
Char Plant. Our char plant produces approximately 107,000 tons of lignite char per year using coal from the Estevan Mine. The char is sold to manufacturers of barbeque briquettes in the United States.
Competition
While the North American coal industry is intensely competitive, we focus on niche coal markets where we take advantage of long-term coal contracts with neighboring power plants. For our open market coal sales, we compete with many other suppliers of coal to provide fuel to power plants. Additionally, coal producers compete with producers of alternative fuels used for electrical power generation, such as nuclear energy, natural gas, hydropower, petroleum and wind. Costs and other factors such as safety, environmental and regulatory considerations relating to these alternative fuels affect the overall demand for coal as a fuel.
Coal - U.S. Segment
We believe that our mines have a competitive advantage based on three factors:
•
all of the mines in our Coal - U.S. Segment are the most economic suppliers to each of their respective principal customers, as a result of transportation advantages over our competitors;
•
nearly all of the power plants we supply were specifically designed to use our coal; and
•
the plants we supply are among the lowest cost producers of electric power in their respective regions and are among the cleaner producers of power from solid fossil fuels.
Because of the foregoing, we believe that our current customers in our Coal - U.S. Segment are more likely to be dispatched to produce power and to continue purchasing coal extracted from our mines.
The principal customers of the Colstrip, Jewett, and Beulah mines are located adjacent to the mines; we deliver the coal for these customers by conveyor belt instead of more expensive means such as truck or rail. The customers of the Savage Mine are located approximately 20 to 25 miles from the mine allowing us to transport coal economically by truck.
The Absaloka Mine faces a different competitive situation. The Absaloka Mine sells its coal in the rail market to utilities located in the northern tier of the United States served by BNSF. These utilities may purchase coal from us or from other producers. We compete with other producers based on price and quality, with the purchasers also taking into account the cost of transporting the coal to their plants. The Absaloka Mine enjoys an over 300-mile rail advantage over its principal competitors from the Southern Powder River Basin in supplying customers located in the northern tier. Rail rates have increased over the last several years by 50 to 100%, which strengthens our competitive advantage.
Coal - Canada Segment
The principal customers of the Paintearth, Sheerness, Genesee, Poplar River and Estevan Mines have power plants that are located adjacent to the mines and the coal is delivered to these customers economically by truck. Our proximity gives us a distinct advantage over our competition.
The Coal Valley Mine produces coal for export customers, and has contracts with railway and port entities for delivery. The coal is railed to and sold at a port facility on the coast of British Columbia, Canada. The export customers are generally Asian power utilities. Our export customers may purchase coal from us or from other producers around the world with similar coal quality, access to ports, and economical shipping to the customer. Some competitors are located closer to the Asian customers' facilities.
Coal - WMLP Segment
General
WMLP is a growth-oriented, low-cost producer and marketer of high-value thermal coal to U.S. utilities and industrial users, and is the largest producer of surface mined coal in Ohio. WMLP markets its coal primarily to large electric utilities with coal-fired, base load scrubbed power plants under long-term coal sales contracts. It focuses on acquiring thermal coal reserves that it can efficiently mine with its large-scale equipment. WMLP’s reserves and operations are well positioned to serve its primary market areas of the Midwest, northeastern United States and Rocky Mountain region.
For the year ended December 31, 2015, WMLP sold $7.9 million tons of coal, 87% of which were sold pursuant to long-term coal supply contracts and generated revenue of approximately $294.6 million. As of December 31, 2015, WMLP owned or controlled approximately 145 million tons of coal reserves, of which 24.3 million tons were leased or subleased to others.
Customers
WMLP’s primary customers are electric utility companies that purchase coal under long-term coal sales contracts. Substantially all of its customers purchase coal for terms of one year or longer, but it also supplies coal on a short-term or spot market basis for some of its customers. In 2015, WMLP derived approximately 58% of its total coal revenues from sales to two customers: American Electric Power Company, Inc. (42%) and Pacificorp Energy, Inc. (16%). A portion of these sales were facilitated by coal brokers.
WMLP Properties
As of December 31, 2015, WMLP operated 14 active surface mines and managed these mines as five mining complexes located in eastern Ohio and one mine located in Wyoming. These mining facilities include two preparation plants, both of which receive, wash, blend, process and ship coal produced from its active mines. The mines are a combination of area, contour, auger and highwall mining methods using truck/shovel and truck/loader equipment along with large production dozers. WMLP also owns and operates seven augers, moving them among its mining complexes, as necessary, and two highwall miner systems. In August 2015, we completed the Kemmerer Drop to WMLP. The Kemmerer Mine supplies approximately 2.7 million tons per year to the adjacent Naughton Power Station via conveyor belt under an agreement that expires in December 2021. Kemmerer also supplies approximately 1.7 million tons a year to various industrial customers, including Tata Chemicals North America Inc. and FMC Corporation, through long-term contracts extending to 2026. These industrial customers are supplied via both short haul rail and truck. Prices under supply agreements related to the Kemmerer Mine are based upon certain actual mine costs and certain inflation/commodity indices for items such as diesel fuel.
Currently, WMLP owns or leases most of the equipment utilized in its mining operations and employs preventive maintenance and rebuild programs to ensure that its equipment is well maintained. The mobile equipment utilized at its mining operations is replaced on an on-going basis with new, more efficient units based on equipment age and mechanical condition.
The following table provides information about the mines held by WMLP as of December 31, 2015. This table does not include any royalty properties as they are discussed below in the “Royalty Revenues” section:
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(1)
Approximate year in which permitted reserves would be exhausted, based on current mine plan and production rates.
(2)
Approximate heat content applies to the coal mined in 2015.
(3)
Approximate sulfur content applies to the tons mined in 2015.
(4)
Mining complex was inactive during 2015.
(5)
The Elkol Underground Mine opened in 1950 and the Sorenson Surface Operations opened in 1963. Tons mined since inception for the Kemmerer Mine are for tons mined from 1950 through 2015.
Royalty Revenues
Tusky Coal Reserves
WMLP began underground mining at the Tusky mining complex in late 2003 after leasing coal reserves from a third party in exchange for a royalty based on tons sold. In June 2005, WMLP sold the Tusky mining complex, and subleased the associated underground coal reserves to the purchaser in exchange for a royalty. There are seven years remaining on WMLP's lease for the underground coal reserves, and the related sublease. The sublessee has the option at any time after December 31, 2022 to elect to have WMLP assign its interest to the sublessee for defined and predetermined consideration. For the year ended December 31, 2015, WMLP did not recognize any royalty revenue on the sublease of the Tusky reserves.
Oil and Gas Reserves
In December 2014, June 2013 and April 2012, WMLP completed the sale of certain oil and gas rights on land in eastern Ohio for $0.2 million, $6.1 million and $6.3 million, respectively, plus future royalties. There were no oil and gas rights sales in 2015. For the fiscal year ended December 31, 2015, WMLP generated $0.9 million in royalty revenue from the receipt of these oil and gas royalties.
Limestone Revenues
At WMLP’s Daron and Strasburg mines, limestone is removed in order to access the underlying coal. WMLP sells this limestone to a third party that crushes the limestone before selling it to local governmental authorities, construction companies and individuals. The third party pays WMLP for this limestone based on a percentage of the revenue it receives from the limestone sales. For the year ended December 31, 2015, WMLP produced and sold 0.7 million tons of limestone, and its revenues included $2.9 million in limestone sales.
Competition
The markets in which WMLP sells its coal are highly competitive. It competes directly with other coal producers and indirectly with producers of other energy products that provide an alternative to coal. While WMLP does not compete with producers of metallurgical coal or lignite, it does have limited competition from producers of Powder River Basin coal (sub-bituminous coal) in its target market area for bituminous coal. WMLP competes on the basis of delivered price, coal quality and reliability of supply. Its principal direct competitors are other coal producers, including (listed alphabetically) Alliance Resource Partners, L.P., CONSOL, Foresight Energy, Hallador Energy Company, Peabody Energy Corp., Rhino Resource Partners, L.P. and various other smaller, independent producers.
Seasonality
Our coal business has historically experienced only limited variability in its results due to the effect of seasons; however, we are impacted by seasonality due to weather patterns and our customer's annual maintenance outages which typically occur during the second quarter. In addition, our customers generally respond to seasonal variations in electricity demand based upon the number of heating degree days and cooling degree days. Due to stockpile management by our customers, our coal sales may not experience the same direct seasonal volatility; however, extended mild weather patterns can impact the demand for our coal. Our sales typically benefit from decreases in customers' stockpiles due to high electricity demand. Conversely, when these stockpiles increase, demand for our coal will typically soften. Further, our ability to deliver coal is impacted by the seasons. Because the majority of our mines are mine-mouth operations that deliver their coal production to adjacent power plants, our exposure to transportation delays or outages as a result of adverse weather conditions is limited.
Material Effects of Regulation
We are subject to extensive regulation with respect to environmental and other matters by federal, state, provincial and local authorities in both the United States and Canada. Federal laws in the U.S. to which we are subject include the Surface Mining Control and Reclamation Act of 1977, or SMCRA, the Clean Air Act, the Clean Water Act, the Toxic Substances Control Act, the Endangered Species Act, the Migratory Bird Treaty Act, the Comprehensive Environmental Response, Compensation and Liability Act, the Emergency Planning and Community Right to Know Act and the Resource Conservation and Recovery Act. The United States Environmental Protection Agency, or EPA, and/or other authorized federal or state agencies administer and enforce these laws. We are also subject to extensive regulation regarding safety and health matters pursuant to the United States Mine Safety and Health Act of 1977, which is enforced by the U.S. Mine Safety and Health Administration ("MSHA"). Provincial laws in Alberta to which we are subject include, among others, the Responsible Energy Development Act, the Mines and Minerals Act, the Coal Conservation Act, the Environmental Protection and Enhancement Act, the Public Lands Act, and the Water Act as well as related regulations, directives, policies and guidelines. Provincial laws in Saskatchewan to which we are subject include, among others, The Crown Minerals Act, The Ecological Reserves Act, The Environmental Assessment Act, The Environmental Management and Protection Act, 2002, The Provincial Lands Act, and the Wildlife Act, 1998, as well as related regulations, directives, policies and guidelines. The federal laws in Canada to which we are subject include, among others, the Fisheries Act, the Canadian Environmental Assessment Act, 2012, the Canadian Environmental Protection Act, 1999, the Species at Risk Act, the Migratory Birds Convention Act as well as related regulations, directives, policies and guidelines, and various provincial and federal climate change laws and initiatives. Non-compliance with federal, tribal and state and provincial laws and regulations could subject us to material administrative, civil or criminal penalties or other liabilities, including suspension or termination of operations. In addition, we may be required to make large and unanticipated capital expenditures to comply with future laws, regulations or orders as well as future interpretations and more rigorous enforcement of existing laws, regulations or orders. Our reclamation obligations under applicable environmental laws will be substantial. Certain of our coal sales agreements contain government imposition provisions that allow the pass-through of compliance costs in some circumstances.
Following passage of The Mine Improvement and New Emergency Response Act of 2006, amending the Federal Mine Safety and Health Act of 1977, MSHA significantly increased the oversight, inspection and enforcement of safety and health standards and imposed safety and health standards on all aspects of mining operations. There has also been a dramatic increase in the dollar penalties assessed by MSHA for citations issued over the past two years. Most of the states in which we operate have inspection programs for mine safety and health. Collectively, federal, state and provincial safety and health regulations in the coal mining industry are comprehensive and pervasive systems for protection of employee health and safety.
Safety is a core value of Westmoreland Coal Company. We use a grass roots approach, encouraging and promoting employee involvement in safety and accept input from all employees; we feel employee involvement is a pillar of our safety excellence. Our Jewett mine won the Sentinels of Safety Award for 2014 which is the United State's most prestigious award given for recognition of mining safely due to the mine having no reportable incidents last year.
Safety performance in 2015 at our mines was as follows:
U.S. Regulation
The following provides brief summaries of certain U.S. federal laws and regulations to which we are subject and their effects upon us:
Surface Mining Control and Reclamation Act. SMCRA establishes minimum national operational, reclamation and closure standards for all surface coal mines. SMCRA requires that comprehensive environmental protection and reclamation standards be met during the course of and following completion of coal mining activities. Permits for all coal mining operations must be obtained from the Federal Office of Surface Mining Reclamation and Enforcement ("OSM"), or, where state regulatory agencies have adopted federally approved state programs under SMCRA, the appropriate state regulatory authority. States that operate federally approved state programs may impose standards that are more stringent than the requirements of SMCRA and OSM’s regulations and, in many instances, have done so. Permitting under SMCRA has generally become more difficult in
recent years, which adversely affects the cost and availability of coal purchased by ROVA, especially in light of significant permitting issues affecting the Central Appalachia region. This difficulty in permitting also affects the availability of coal reserves at our coal mines. It is our policy to comply in all material respects with the requirements of the SMCRA and the state and tribal laws and regulations governing mine reclamation.
Clean Air Act and Related Regulations. The U.S. Clean Air Act ("CAA"), and comparable state laws that regulate air emissions affect coal mining operations both directly and indirectly. Direct impacts on coal mining and processing operations include Clean Air Act permitting requirements and emission control requirements relating to air pollutants, including particulate matter, which may include controlling fugitive dust. The Clean Air Act indirectly affects coal mining operations by extensively regulating the emissions of particulate matter, sulfur dioxide, nitrogen oxides, mercury and other compounds emitted by coal-fired power plants. It also affects us directly because ROVA is subject to significant regulation under the Clean Air Act. In recent years, Congress has considered legislation that would require increased reductions in emissions of sulfur dioxide, nitrogen oxide and mercury, as well as GHGs. The air emissions programs, regulatory initiatives and standards that may affect our operations, directly or indirectly, include, but are not limited to, the following:
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Greenhouse Gas Emissions Standards. In August of 2015, EPA finalized standards for greenhouse gases for new and modified electric generating units (EGUs) referred to as “new source performance standards” or NSPS. The final NSPS for coal-fired EGUs is set at 1,400 pounds of CO2 / megawatt hour on an average annual basis which would, with few possible exceptions, require the installation of partial carbon capture and sequestration at new or modified coal-fired EGUs. Under the CAA, new source performance standards like the GHG NSPS have binding effect from the date of the proposal, which in this case was January 8, 2014. Therefore, any new coal-fired EGU must comply with this standard, which is likely to be major obstacle to the construction and development of any new coal-fired generation capacity. Existing coal-fired generation, however, is also now subject to GHG performance standards that the EPA asserts will reduce GHG emissions from the power sector by 32% from 2005 levels by 2030. At the same time the EPA issued the GHG NSPS, EPA finalized existing source standards for fossil-fuel fired power plants, which EPA refers to as the Clean Power Plan. The final Clean Power Plan imposes stringent standards on existing fossil-fuel fired EGUs that reflect EPA’s assessment of the “best system of emission reduction,” (BSER) including (1) average heat rate improvements of 6% for coal-fired power plants; (2) the re-dispatch of power based on an assumption that underutilized capacity at natural gas combined cycle facilities can be increased to an average of 75% of net summer capacity; and (3) the substitution of coal generation with renewable energy. These existing source standards are implemented by the states, which must meet individual GHG emission “goals” beginning in 2022 with phased reductions through 2030. Each state can choose either a rate-based or a mass-based goal that reflects the mix of natural gas and coal-fired generation in the state. The final goals have a greater impact on states with substantial coal-fired generation; Wyoming and North Dakota, for example, are faced with greater than 40% emission reductions from a 2012 baseline. The states have until September of 2016 to submit plans to EPA to implement and enforce the state-specific BSER, although two-year extensions be requested by states in an initial submittal. States and industry groups challenged the rule in the U.S. Court of Appeals for the D.C. Circuit and requested a stay pending judicial review. Although the D.C. Circuit denied the stay request, in February of 2016, the U.S. Supreme Court issued a stay of the Clean Power Plan pending judicial review of the rule, including potential review by the Supreme Court. The D.C. Circuit is reviewing the rule under an expedited briefing schedule, with oral arguments to be held in June of 2016. A number of states, including Montana and Utah, have ceased development of implementation plans, while others, including Colorado, are continuing to work on plan development. If upheld by the courts, these rules have the potential to adversely affect our revenues and profitability, although it is difficult at this stage to determine the timing and extent of any such effects, or to determine the requirements of state plans resulting from these proposals that may ultimately be promulgated and require implementation. In June 2014, the U.S. Supreme Court in UARG v. EPA struck down the EPA’s GHG permitting rules to the extent they imposed on sources a requirement to obtain an air emissions permit and comply with emissions limits solely as a result of GHG emissions. The Court upheld the EPA’s authority to impose the Best Available Control Technology (“BACT”) on large industrial sources such as power plants that are otherwise required to obtain an air emissions permit under the Prevention of Significant Deterioration program or the Title V program of the Clean Air Act. In April 2015, the U.S. Court of Appeals for the D.C. Circuit rejected motions filed by industry groups and certain states arguing that GHG permitting rules should be vacated in their entirety while EPA undertakes a new rulemaking determining how to address the Supreme Court’s ruling. Therefore the regulatory provisions addressing GHG emissions from large industrial sources, such as fossil-fuel fired EGUs, remain in place. EPA has not yet initiated a rulemaking to address the Supreme Court’s decision.
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Mercury Air Standards. In February 2012, the EPA published national emission standards under Section 112 of the CAA setting limits on hazardous air pollutant emissions from coal- and oil-fired EGUs, often referred to as the “Mercury Air Toxics Standards,” or “MATS Rule.” While the MATS Rule will generally require all coal- and oil-
fired EGUs to reduce their hazardous air pollutant emissions, it is particularly problematic for any new coal-fired sources. The EPA agreed to reconsider the new source standards in response to requests by industry and published new source standards in April 2013. In June 2013, the EPA reopened for 60 days the public comment period on certain startup and shutdown provisions included in the November 2012 proposal.. In June of 2015, the U.S. Supreme Court reversed the U.S. Court of Appeals for the D.C. Circuit and held that EPA had failed to properly consider costs when assessing whether to regulate fossil fuel-fired EGUs under the hazardous air pollutant provisions of the Clean Air Act, referring to the agency’s own estimate that the rule would cost power plants nearly $10 billion a year. The D.C. Circuit remanded the rule to EPA to conduct a cost assessment but without vacatur, allowing the rule to remain in effect while EPA conducts the rulemaking. On December 1, 2015, EPA published a proposed supplemental finding that regulation of EGUs is still “appropriate and necessary” in light of the costs to regulate hazardous air pollutant emissions from the source category. EPA indicated that it expects to issue a final finding by April 15, 2016.
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National Ambient Air Quality Standards (“NAAQS”) for Criteria Pollutants. The CAA requires the EPA to set standards, referred to as NAAQS, for six common air pollutants, including nitrogen oxide and sulfur dioxide. Areas that are not in compliance (referred to as non-attainment areas) with these standards must take steps to reduce emissions levels. Meeting these limits may require reductions of nitrogen oxide and sulfur dioxide emissions. Although our operations are not currently located in non-attainment areas, we could be required to incur significant costs to install additional emissions control equipment, or otherwise change our operations and future development if that were to change. On June 22, 2010, the EPA published a final rule that tightens the NAAQS for sulfur dioxide. On February 17, 2012, the EPA published final NAAQS for nitrogen dioxide. On January 15, 2013, the EPA published final NAAQS for particulate matter; the EPA lowered the annual standard for particles less than 2.5 micrometers in diameter but maintained the NAAQS for particles less than 10 micrometers in diameter. EPA finalized designations for the sulfur dioxide NAAQS in 2013 for a handful of counties and delayed designations for the remainder of the country. EPA has proposed guidance that would allow states to use both monitoring and modeling for the remaining designations, but has not finalized the guidance or set any deadlines for state recommendations. EPA finalized nonattainment designations for nitrogen dioxide in January 2012. We do not know whether or to what extent these developments might affect our operations or our customers’ businesses. In 2008, the EPA finalized the current 8-hour ozone standard. In October 2015, the EPA issued a final rule lowering the ozone standard further. While it is likely that these and any future developments resulting in stricter NAAQS will to some degree adversely affect us, it is difficult at this stage to determine the timing and extent of such effects.
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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 reduction effective in 2014. On December 15, 2011, the EPA finalized a supplemental rule making to require Iowa, Michigan, Missouri, Oklahoma and Wisconsin to make summertime reductions to nitrogen oxide emissions under the CSAPR ozone-season control program. However, on December 30, 2011, the U.S. Court of Appeals for the District of Columbia Circuit stayed the implementation of CSAPR pending resolution of judicial challenges to the rules and ordered the EPA to continue enforcing the CAIR until the pending legal challenges have been resolved. In August 2012, the U.S. Court of Appeals vacated the CSAPR in a 2-to-1 decision and left the CAIR standards in place. In April 2014, the U.S. Supreme Court reversed the D.C. Circuit decision that vacated the CSAPR and remanded the cases for further proceedings consistent with the Court’s opinion, which acknowledged the possibility that under certain circumstances some states may have a basis to bring a particularized, as-applied challenge to the rule. The EPA filed a motion with the D.C. Circuit to lift its stay of the CSAPR and to toll for three years all deadlines that had not already passed as of the date the stay was granted. The D.C. Circuit granted the EPA’s motion in October 2014, and scheduled oral argument on the remaining challenge to the CSAPR for March 2015. In November, 2014 the EPA issued a ministerial rule aligning the CSAPR implementation dates with the Court’s order, with phase 1 reductions beginning in January 2015, and more stringent phase 2 reductions in January 2017. In July 2015, the D.C. Circuit remanded to EPA portions of the 2014 sulfur dioxide and ozone budgets on grounds the reductions were greater than necessary to reduce impacts on downwind states, but did not vacate any portion of the rule. The EPA has indicated that it will address these issues in future rulemakings, but that phase 1 reductions will begin in January 2015, with more stringent phase 2 reductions in January 2017 as necessary.
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Other Programs. A number of other air-related programs may affect the demand for coal and, in some instances, coal mining directly. For example, the EPA has initiated a regional haze program designed to protect and improve visibility at and around national parks, national wilderness areas and international parks. The EPA’s new source review program under certain circumstances requires existing coal-fired power plants, when modifications to those plants significantly change emissions, to install the more stringent air emissions control equipment required of new plants, and concerns about potential failures to comply have resulted in a number of high-profile enforcement actions and settlements over the years resulting in some instances in settlements under which operators install expensive new emissions control equipment. The Acid Rain program under Title IV of the CAA continues to impose limits on overall sulphur dioxide and nitrogen oxide emissions from regulated EGUs. In June 2013, President Obama issued a Climate Action Plan, which included a focus on methane reductions from coal mines. In January 2015, the Administration issued its methane strategy, but it did not include requirements for coal mines. In 2014 the D.C. Circuit upheld EPA’s 2013 decision, based on resource constraints, not to list coal mines as a category of air pollution sources that endanger public health or welfare under Section 111 of the CAA and establish related emission standards.
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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.
Clean Water Act. The Clean Water Act ("CWA") and corresponding state and local laws and regulations affect coal mining and power generation operations by restricting the discharge of pollutants, including dredged or fill materials, into waters of the U.S. The CWA provisions and associated state and federal regulations are complex and subject to amendments, legal challenges and changes in implementation. In May 2015, the EPA and the U.S. Army Corps of Engineers jointly issued a final rule to clarify which waters and wetlands are subject to regulation under the CWA. The implementation of this rule was stayed nationwide in October 2015. Recent court decisions, regulatory actions and proposed legislation have created uncertainty over CWA jurisdiction and permitting requirements that could either increase or decrease the cost and time spent on CWA compliance.
Endangered Species Act. The Federal Endangered Species Act ("ESA"), and similar state laws protect species threatened with extinction. Protection of endangered and threatened species may cause us to modify mining plans or develop and implement species-specific protection and enhancement plans to avoid or minimize impacts to endangered species or their habitats. A number of species indigenous to the areas where we operate are protected under the ESA. Based on the species that have been identified and the current application of applicable laws and regulations, we do not believe that there are any species protected under the ESA or state laws that would materially and adversely affect our ability to mine coal from our properties.
Resource Conservation and Recovery Act. We may generate wastes, including “solid” wastes and “hazardous” wastes that are subject to the federal Resource Conservation and Recovery Act ("RCRA"), and comparable state statutes, although certain mining and mineral beneficiation wastes and certain wastes derived from the combustion of coal currently are exempt from regulation as hazardous wastes under RCRA. The EPA has limited the disposal options for certain wastes that are designated as hazardous wastes under RCRA. Furthermore, it is possible that certain wastes generated by our operations that currently are exempt from regulation as hazardous wastes may in the future be designated as hazardous wastes, and therefore be subject to more rigorous and costly management, disposal and clean-up requirements.
The EPA determined that coal combustion residuals (“CCR”) do not warrant regulation as hazardous wastes under RCRA in May 2000. Most state hazardous waste laws do not regulate CCR as hazardous wastes. The EPA also concluded that beneficial uses of CCR, other than for mine filling, pose no significant risk and no additional national regulations of such beneficial uses are needed. However, the EPA determined that national non-hazardous waste regulations under RCRA are warranted for certain wastes generated from coal combustion, such as coal ash, when the wastes are disposed of in surface impoundments or landfills or used as minefill. EPA Administrator Gina McCarthy signed the final rule relating to the disposal
of CCR from electric utilities on December 19, 2014 and submitted it to the Federal Register for publication. The final rule regulates CCR as solid waste under RCRA. The final rule establishes national minimum criteria for existing and new CCR landfills, surface impoundments and lateral expansions. The criteria include location restrictions, design and operating criteria, groundwater monitoring and corrective action, closure requirements and post-closure care and recordkeeping, notification and internet posting requirements. The rule is largely silent on the reuse of coal ash. These changes in the management of CCR could increase both our and our customers’ operating costs and potentially reduce their ability to purchase coal. In addition, contamination caused by the past disposal of CCR, including coal ash, could lead to citizen suit enforcement against our customers under RCRA or other federal or state laws and potentially reduce the demand for coal.
Comprehensive Environmental Response, Compensation, and Liability Act. Under the Comprehensive Environmental Response, Compensation, and Liability Act, also known as CERCLA or Superfund, and similar state laws, responsibility for the entire cost of cleanup of a contaminated site, as well as natural resource damages, can be imposed upon current or former site owners or operators, or upon any party who released one or more designated “hazardous substances” at the site, regardless of the lawfulness of the original activities that led to the contamination. CERCLA also authorizes the EPA and, in some cases, third parties to take actions in response to threats to public health or the environment and to seek to recover from the potentially responsible parties the costs of such action. In the course of our operations, we may have generated and may generate wastes that fall within CERCLA’s definition of hazardous substances. We may also be an owner or operator of facilities at which hazardous substances have been released by previous owners or operators. We may be responsible under CERCLA for all or part of the costs of cleaning up facilities at which such substances have been released and for natural resource damages. We have not, to our knowledge, been identified as a potentially responsible party under CERCLA, nor are we aware of any prior owners or operators of our properties that have been so identified with respect to their ownership or operation of those properties. We also must comply with reporting requirements under the Emergency Planning and Community Right-to-Know Act and the Toxic Substances Control Act.
Climate Change Legislation and Regulations. Numerous proposals for federal and state legislation have been made relating to GHG emissions (including carbon dioxide) and such legislation could result in the creation of substantial additional costs in the form of taxes or required acquisition or trading of emission allowances. Many of the federal and state climate change legislative proposals use a “cap and trade” policy structure, in which GHG emissions from a broad cross-section of the economy would be subject to an overall cap. Under the proposals, the cap would become more stringent with the passage of time. The proposals establish mechanisms for GHG sources such as power plants to obtain “allowances” or permits to emit GHGs during the course of a year. The sources may use the allowances to cover their own emissions or sell them to other sources that do not hold enough emissions for their own operations. Some states, including California, and regional groups including a number of states in the northeastern and mid-Atlantic regions of the US that are participants in a program known as the Regional Greenhouse Gas Initiative (often referred to as “RGGI”), which is limited to fossil-fuel-burning power plants, have enacted and are currently operating programs that, in varying ways and degrees, regulate GHGs.
In addition, the EPA, acting under existing provisions of the Clean Air Act, has begun regulating emissions of GHG, including the enactment of GHG-related reporting and permitting rules as described above. In June of 2014, the U.S. Supreme Court overturned EPA’s GHG permitting rules to the extent they required permits based solely on emissions of GHG. Large sources of air pollutants could still be required to install GHG emission reduction technology. Underground coal mines remain subject to EPA’s GHG Reporting Program, which required mines to submit annual GHG emission estimates to EPA, but that program has not been extended to surface coal mines.
The impact of GHG-related legislation and regulations, including a “cap and trade” structure, on us will depend on a number of factors, including whether GHG sources in multiple sectors of the economy are regulated, the overall GHG emissions cap level, the degree to which GHG offsets are allowed, the allocation of emission allowances to specific sources and the indirect impact of carbon regulation on coal prices. We may not recover from our customers the costs related to compliance with regulatory requirements imposed on us due to limitations in our agreements.
Passage of additional state or federal laws or regulations regarding GHG emissions or other actions to limit carbon dioxide emissions could result in fuel switching from coal to other fuel sources by electricity generators and thereby reduce demand for our coal or indirectly the prices we receive in general. In addition, political and regulatory uncertainty over future emissions controls have been cited as major factors in decisions by power companies to postpone new coal-fired power plants. If these or similar measures, such as controls on methane emissions from coal mines, are ultimately imposed by federal or state governments or pursuant to international treaties, our operating costs or our revenues may be materially and adversely affected. In addition, alternative sources of power, including wind, solar, nuclear and natural gas could become more attractive than coal in order to reduce carbon emissions, which could result in a reduction in the demand for coal and, therefore, our revenues. Similarly, some of our customers, in particular smaller, older power plants, could be at risk of significant reduction in coal burn or closure as a result of imposed carbon costs. The imposition of a carbon tax or similar regulation could, in certain situations,
lead to the shutdown of coal-fired power plants, which would materially and adversely affect our coal and power plant revenues.
Bonding Requirements. Federal and state laws require mine operators to assure, usually through the use of surety bonds, payment of certain long-term obligations, including the costs of mine closure and the costs of reclaiming the mined land. The costs of these bonds have fluctuated in recent years, and the market terms of surety bonds have generally become more favorable to us. Surety providers are requiring smaller percentages of collateral to secure a bond, which will require us to provide less cash to collateralize bonds to allow us to continue mining. These changes in the terms of the bonds have been accompanied, at times, by an increase in the number of companies willing to issue surety bonds. As of December 31, 2015, we had posted an aggregate of $487.3 million in surety bonds for reclamation purposes, with approximately $102.9 million of cash collateral.
Regulation applicable to ROVA. With respect to our Power segment, ROVA is among the newer and cleaner coal-fired power plants in the United States. Under Title IV of the Clean Air Act, ROVA is exempt from, but may opt-in to receive allocations of sulfur dioxide emission allowances. The plants are among the lowest coal-fired emitters of mercury in the country. Emissions tests performed in 2015 have been submitted to the EPA and have demonstrated that both ROVA units 1 and 2 are compliant with the MATS Rule which must be demonstrated every year. Currently, ROVA is a consumer of sulfur dioxide allowances and nitrogen oxide allowances, and we expect an increase in costs associated with nitrogen oxide allowances at ROVA. With regard to coal ash regulations, ROVA landfills its combustion waste. The landfills are lined and we believe they meet North Carolina Department of Solid Waste regulations. However, on December 19, 2014, the EPA Administrator executed a final rule relating to the disposal of CCR for electric utilities. The rule regulates CCR as a solid waste under RCRA and establishes national minimum criteria for existing and new CCR landfills, surface impoundments and lateral expansions. The criteria include location restrictions, design and operating criteria, groundwater monitoring and corrective action, closure requirements and post-closure care and recordkeeping, notification and internet posting requirements. At this time we are unable to predict the impact that any new regulations might have on our operations.
An important factor relating to the impact of GHG-related legislation and regulations and any other environmental regulations on our Power segment will be our ability to recover the costs incurred to comply with any regulatory requirements that the government ultimately imposes. We may not be able to recover the costs related to compliance with regulatory requirements imposed on us due to limitations in our power purchase agreements. If we are unable to recover such costs incurred by ROVA through allowances or other methods, it could have a material adverse effect on our results of operations at ROVA.
Canadian Regulation
The following is intended as a general overview of certain provincial laws and regulations in Alberta and the federal laws applicable therein to which we are subject and their potential effects upon us. We note that the consequences and penalties arising from the application of any of the below listed enactments are varied and fact specific. Accordingly, the summary that follows should not be considered a comprehensive or conclusive assessment of the possible outcomes of a contravention of the legislation discussed below:
Responsible Energy Development Act. The Responsible Energy Development Act (the “REDA”) establishes the Alberta Energy Regulator (the “AER” or the “Regulator”) and sets out its mandate, structure, powers, duties and functions. The AER administers, among others, the following statutes and accompanying regulations in relation to coal mining and related activities in Alberta: the Mines and Minerals Act, the Coal Conservation Act, the Environmental Protection and Enhancement Act, the Public Lands Act, and the Water Act. The REDA empowers the AER to carry out compliance and enforcement functions under the various pieces of legislation it administers as well as grants it the power to order the payment of administrative penalties.
Mines and Minerals Act. The Mines and Minerals Act (the “MM Act”), and its underlying regulations, governs the management and disposition of rights in Crown owned mines and minerals. The AER recently assumed jurisdiction over issuing exploration authorizations under the MM Act, which any person conducting mining exploration in Alberta is required to obtain in advance of carrying out an exploration program. Exploration programs under the MM Act are subject to investigations and inspections and a contravention of an exploration authorization or of the provisions of the MM Act may result in cancellation of that exploration authorization and/or financial penalties.
Coal Conservation Act. The Coal Conservation Act (the “CC Act”), and its underlying rules, applies to every mine, coal processing plant and in situ coal scheme in the Province of Alberta, and to all coal produced and transported in Alberta. The CC Act imposes permitting, licensing and approval requirements on operators of coal mines and coal processing plants. The CC Act imposes certain environmental conservation requirements on mine operators in relation to, among other things, pollution control, surface abandonment, and prevention of waste. Similar to the US bonding requirements mentioned above, the
Regulator may require that we deposit financial security to ensure payment of costs associated with suspension of our operations and/or reclamation. Lastly, under the CC Act the Regulator can conduct an inquiry into any matter connected with our Alberta mining operations, the findings of which may result in prosecution for an offense, financial penalties, or injunctions in relation to our operations.
Environmental Protection and Enhancement Act. Under the Environmental Protection and Enhancement Act (the “EPEA”), and its underlying regulations, the AER is responsible for administering environmental impact assessments, and issuing approvals and other authorizations in respect of certain aspects of coal mining operations in Alberta that have the potential to impact the environment. The specific terms and conditions of an EPEA approval may govern emission and effluent limits, monitoring and reporting requirements, research needs, siting and operating criteria, and decommissioning and reclamation requirements. The AER also administers and enforces provisions under the EPEA that concern spills and releases, contaminated sites, land surface reclamation, and hazardous wastes. The Mine Financial Security Program under the EPEA requires us to have sufficient financial resources for carrying out suspension, abandonment, remediation, and surface reclamation work to the standards established by the province and to maintain care and custody of the land until a reclamation certificate has been issued. The Regulator may exercise broad enforcement powers under the EPEA, including conducting compliance checks, inspections and investigations, issuing enforcement orders, taking enforcement actions, issuing clean-up orders, suspending and/or canceling operating authorizations, demanding cost recovery or charging us for an offense under the EPEA; all of which may have a material adverse effect on our business, depending on the specific circumstances surrounding the enforcement action taken by the Regulator.
Public Lands Act. Under the Public Lands Act, the AER carries out its responsibility of ensuring that energy exploration, development, and ongoing operations on public land, including coal mining, are carried out in a responsible manner and in accordance with applicable legislation. The AER amends, maintains, and inspects all land-use dispositions and authorizations for energy activities. The AER also administers the enforcement and compliance provisions of the Public Lands Act, which empower it to cancel, suspend or amend a disposition where its terms and conditions or the provisions of the legislation have been contravened and to issue financial penalties in respect of offences under the Public Lands Act. Similar to contraventions of other pieces of legislation discussed in this section, an enforcement action or a penalty has the potential to constitute a material adverse effect on our operations.
Water Act. The Water Act, and its underlying regulations, requires that authorizations be obtained prior to undertaking construction activities around, and prior to diverting water from, a water body. Under the Water Act, a corporation conducting an activity without the requisite approval or in contravention of the specific terms and conditions of an authorization is liable to a fine and/or administrative penalty, which may have a material adverse effect on our business.
The Crown Minerals Act. Similar to the MM Act in Alberta, the Crown Minerals Act (the “CM Act”), and its underlying regulations, governs the management and disposition of rights in Crown owned mines and minerals. The Saskatchewan Ministry of Economy administers the CM Act and the issuance of dispositions authorizing the exploration and development of coal resources in the province. Contravention of the terms of a Crown disposition or the provisions of the CM Act may result in cancellation of that disposition and/or financial penalties, both of which may have a material adverse effect on our business.
The Ecological Reserves Act. The Ecological Reserves Act (the “ER Act”) protects unique, natural ecosystems and landscape features in Saskatchewan through the designation of Crown land as ecological reserves. Under the ER Act, the Lieutenant Governor in Council may make regulations and orders designating any Crown land as an ecological reserve, enlarging any ecological reserve, and restricting the activities which may be carried out on an existing ecological reserve. Designation of either of our Saskatchewan mine properties as an ecological reserve may restrict our mining activities on those properties, or cause us to modify mining plans; however, we do not have any reason to believe that either of our Saskatchewan properties are at risk of being designated an ecological reserve at this time.
The Environmental Assessment Act. The Environmental Assessment Act (the “EA Act”) provides a means to ensure that development proceeds with adequate environmental safeguards and in a manner broadly understood by and acceptable to the public through the integrated assessment of environmental impact. Under the EA Act, the Saskatchewan Ministry of Environment is responsible for administering environmental assessments, and issuing approvals and other authorizations in respect of certain aspects of coal mining operations in Saskatchewan that have the potential to impact the environment. Similar to the AER’s powers in relation to environmental impact assessments issued under the EPEA, the Ministry of Environment may issue an EA Act approval on any terms and conditions considered necessary or advisable to protect the environment. The Ministry of Environment has broad enforcement powers under the EA Act, including enjoining a development contrary to the EA Act or the terms and conditions of any ministerial approval, conducting investigations, and issuing financial penalties for offenses under the EA Act; all of which may have a material adverse effect on our business, depending on the specific circumstances surrounding the enforcement action taken by the Ministry of Environment.
The Environmental Management and Protection Act, 2002. The Environmental Management and Protection Act, 2002 (the “EMP Act”), and its underlying regulations, protects the air, land and water resources of Saskatchewan through regulating and controlling potentially harmful activities and substances. The Saskatchewan Ministry of Environment administers and enforces provisions under the EMP Act that concern unauthorized discharges of substances into the environment, contaminated sites, surface land reclamation, hazardous waste, water quality, and activities around water bodies. The Saskatchewan Ministry of Environment may exercise broad enforcement powers under the EMP Act, including conducting compliance checks, inspections and investigations, issuing environmental protection orders, suspending or canceling operating authorizations, demanding cost recovery or charging us for an offence under the EMP Act; all of which may have a material effect on our business, depending on the specific circumstances surrounding the enforcement action taken by the Ministry of Environment.
The Provincial Lands Act. The Provincial Lands Act (the “PL Act”) creates authority for the Saskatchewan Ministry of Environment to carry out its responsibilities in relation to the management, transfer, sale, lease or other disposition of Crown lands, including lands used for coal mining. The Ministry of Environment also administers the enforcement and compliance provisions of the PL Act, which may include cancellation of a disposition where its terms and conditions or the provisions of the legislation have been contravened and to issue financial penalties in respect of offenses under the PL Act. Similar to contraventions of other legislation discussed in this section, an enforcement action or a penalty has the potential to constitute a material adverse effect on our operations.
The Wildlife Act, 1998. The Wildlife Act, 1998 (the “Wildlife Act”) provides for the management, conservation and protection of wildlife resources through the issuance and revocation of licenses, the prosecution of wildlife offenses and the establishment of annual hunting seasons. The Wildlife Act includes provisions to designate and protect species at risk in Saskatchewan, of which there are currently 15 at-risk plants and animals identified in the Wildlife Act. Identification of a species at risk may cause us to modify mining plans or develop and implement protection plans to avoid or minimize impacts to species protected under the Wildlife Act; however, we do not believe that there are any species protected under the Wildlife Act that would materially and adversely affect our ability to mine coal from our Saskatchewan properties.
Fisheries Act. The Fisheries Act, and its underlying regulations, contains two key provisions on conservation and protection of fish habitat that have the potential to have a material effect on our business. The Department of Fisheries and Oceans (“DFO”) administers the key habitat protection provision prohibiting any work or undertaking that would cause harm to fish or fish habitat. The Fisheries Act also prohibits the release of deleterious substances into waters frequented by fish. In terms of potential material adverse effects to our business resulting from a contravention of the Fisheries Act, enforcement of the habitat protection and pollution prevention provisions of the Fisheries Act is carried out through inspections to monitor or verify compliance, investigations of violations, issuance of warning, directions by Fishery Inspectors, authorizations and Ministerial orders, and court actions, such as injunctions, prosecution, court orders upon conviction and civil suits for recovery of costs.
Canadian Environmental Assessment Act, 2012. The Canadian Environmental Assessment Act, 2012 (the “CEAA”) is the primary federal statute for environmental assessments. The CEAA requires that an environmental assessment for projects that are listed in the Regulations Designating Physical Activities be completed prior to federal authorities making decisions that allow a project to proceed (i.e. prior to issuing certain licenses, disposing of federal lands, providing funding for a project). Projects that require an environmental assessment under the CEAA include, among others, the construction, operation, decommissioning and abandonment, in a wildlife area or a migratory bird sanctuary, of a new mine; the construction, operation, decommissioning and abandonment of a new dam or dyke or the expansion of an existing dam or dyke in certain circumstances; the construction, operation, decommissioning and abandonment of a new structure for the diversion of certain amounts of water; and the construction, operation, decommissioning and abandonment of a new coal mine with a coal production capacity of 3,000 t/day or more.
Canadian Environmental Protection Act, 1999. The Canadian Environmental Protection Act, 1999 (the “CEPA”) focuses on the prevention and management of risks posed by toxic and other harmful substances, as well as management of environmental and human health impacts of hazardous wastes, environmental emergencies and other sources of pollution. Certain substances used and/or produced, as well as downstream wastes generated through the course of our mining and processing operations may bring our business under the purview of the CEPA. The CEPA provides the authority to carry out inspections and investigations to ensure that regulations made under the CEPA and the CEPA itself are followed. Similar to the enforcement provisions of other environmental laws and regulations discussed herein, enforcement tools under the CEPA may include warnings, directions to prevent releases, tickets, orders requiring remedial measures, injunctions, prosecution, and financial penalties. Subject to the specific circumstances of a contravention of the CEPA, an enforcement action taken under the CEPA has the potential to cause a material adverse effect to our business.
Species at Risk Act. The purposes of the Species at Risk Act (the “SARA”) are to prevent wildlife species in Canada from disappearing, to provide for the recovery of wildlife species that no longer exist in the wild in Canada, endangered, or
threatened as a result of human activity, and to manage species of special concern to prevent them from becoming endangered or threatened. The SARA may affect our operations if a species at risk is found at any time throughout the year on a property in Canada in which we have an interest. As with the protection of endangered species legislation in the US, identification of a species at risk may cause us to modify mining plans or develop and implement protection plans to avoid or minimize impacts to species protected by the SARA; however, we do not believe that there are any species protected under the SARA that would materially and adversely affect our ability to mine coal from our properties.
Migratory Birds Convention Act, 1994. Environment Canada is responsible for implementing the Migratory Birds Convention Act, 1994 (the “MBC Act”), which provides for the protection and conservation of migratory bird populations by regulating potentially harmful human activities. The MBC Act prohibits, among other things, the deposit of harmful substances in waters or areas frequented by migratory birds and a permit must be issued for all activities affecting migratory birds. Any person that commits an offence under the MBC Act is liable to a fine or to imprisonment. A contravention of the MBC Act may result in cancellation or suspension of a permit issued under the MBC Act and a compensatory order for costs incurred by others as a result of a contravention may be issued.
Climate Change Legislation and Regulations. Similar to climate change legislation, regulations, and proposals in the US, the direct and indirect costs of various GHG regulations, existing and proposed in Canada, may adversely affect our business. Equipment that meets future emission standards may not be available on an economic basis and other compliance methods to reduce our emissions or emissions intensity to future required levels may significantly increase operating costs or reduce output. Offset, performance or fund credits may not be available for acquisition or may not be available on an economic basis. Any failure to meet emission reduction compliance obligations may materially adversely affect our business and result in fines, penalties and the suspension of operations. There is also a risk that one or more levels of government could impose additional emissions or emissions intensity reduction requirements or taxes on emissions created by us or by consumers of our products. The imposition of such measures might negatively affect our costs and prices for our products and have an adverse effect on earnings and results of operations.
Alberta’s Climate Change and Emissions Management Act (the “CCEM Act”) and its accompanying Specified Gas Emitters Regulation (the “SGE Regulation”) requires a reduction in GHG emissions intensity for certain large GHG emitting facilities in Alberta. This system features emissions trading between regulated facilities and allows the use of offsets generated by projects in Alberta. Generally, the SGE Regulation establishes that companies emitting more than 100,000 tons of direct emissions in 2003, 2004, 2005, and 2006 in commercial operation must reduce their net emissions intensity by 12%. New facilities must reduce their emissions by 2% per year, beginning on their 4th year of operation. There are financial penalties for non-compliance for every ton of carbon dioxide equivalent over a facility’s net emission intensity limit as well as for contraventions of other provisions contained in the SGE Regulation.
Future federal legislation, including the implementation of potential international requirements enacted under Canadian law, as well as provincial emissions reduction requirements, may require the reduction of GHG or other industrial air emissions, or emission intensity, from our operations and facilities. Mandatory emissions reduction requirements may result in increased operating costs and capital expenditures. We are unable to predict the impact of emissions reduction legislation on our business and it is possible that such legislation may have a material effect on our business, financial condition, results of operations and cash flows.
Power Segment
General
We own two coal-fired power-generating units in Weldon, North Carolina with a total capacity of approximately 230 megawatts, which we refer to collectively as ROVA. We built ROVA, which commenced operations in 1994, as a Public Utility Regulatory Policies Act co-generation facility to supply Dominion North Carolina Power (“DNCP”). ROVA is held by our wholly-owned subsidiary Westmoreland Partners. All of the tangible and intangible assets of Westmoreland Partners are encumbered by liens securing our 8.75% Notes and WCC Term Loan Facility.
Coal Supply
ROVA purchases coal under short-term contracts from coal suppliers with identified reserves located in Central Appalachia, and supplies the power it produces to DNCP.
Customer
ROVA supplies a portion of the power it produces to DNCP and generates revenues from such sales, as well as through the settlement of related power hedging arrangements. In 2015, the sale of power by ROVA to DNCP accounted for approximately 6% of our consolidated revenues. The Power Segment is impacted by seasonality due to the impact of weather
on customer demand and scheduled maintenance outages typically performed in the spring and fall, as well as the hedging agreement described below.
Westmoreland Partners is party to a consolidated power purchase and operating agreement (the “Consolidated Agreement”) with Virginia Electric Power Company that is scheduled to terminate in March 2019. The Consolidated Agreement provides for the sale to DNCP and its affiliates of all of ROVA’s net electrical output and dependable capacity. The Consolidated Agreement permits Westmoreland Partners to mitigate its cash losses through the sale to DNCP of substitute power not produced by ROVA during periods when it is uneconomical to operate the ROVA units. Under the Consolidated Agreement, we forego dispatching the ROVA units in low demand periods and maintain them in idle status. During such low demand periods, we meet DNCP’s power needs with fixed-price purchased power when doing so is more economically attractive than our physically operating the ROVA plants to generate power. Alternatively, we operate the ROVA plants, sell our produced power to DNCP and resell the fixed-price purchased power in the open market. When we operate the ROVA plants and resell our fixed-price purchased power into the open market, any such resales are made at prevailing market rates. In the event that the prevailing market price for power falls below the level of our hedged position during periods when we are reselling the fixed-price purchased power in the open market, those resales result in losses to us. The fixed-price purchased power contracts cover the period from April 2014 to March 2019 and contracted power prices range from $41.05 to $55.20 megawatts per hour, with a weighted average contract price of $43.93 over the remaining contract lives. For the year ended December 31, 2015, we incurred losses related to these hedging arrangements of $5.6 million. Based on current market pricing trends, we expect to experience losses from time to time under these hedging arrangements when the market price for power is not commensurate with our hedged position. Further, we are required to post collateral to cover certain projected long-term losses under these hedging arrangements based on the market price for power. The amount of such collateral may be significant and may negatively impact our liquidity. See “Risk Factors - Risks Relating to our Business and Operations - Our hedging arrangement related to our ROVA facility may result in losses if the market price for power drops below the level of our hedged position and, under certain circumstances, requires us to post additional collateral.”
During the fourth quarter of 2015 we evaluated our ROVA asset group for impairment primarily as a result of an impairment indicator related to the continued decline in forecasted electricity prices. We believe the depressed power prices will persist in the future. The asset group is comprised of property, plant, and equipment and related capital spares used to generate electricity. Our evaluation concluded that the long-lived assets at ROVA were impaired, and the carrying value of those assets was written down to zero as a result of an impairment charge of $133.1 million, with the charge included in the Loss on Impairment line item on the Consolidated Statement of Operations for the year ended December 31, 2015.
Heritage Segment
Our Heritage Segment includes the cost of heritage benefits we provide to former mining operation employees. The heritage costs consist of payments to our retired workers for medical benefits, workers’ compensation benefits, black lung benefits and combined benefit fund premiums to plans for United Mine Workers of America (“UMWA”) retirees required by statute. Canadian heritage costs include retiree medical benefits, statutory workers’ compensation premiums, and contributions to pension plans.
Corporate Segment
Our Corporate Segment includes primarily corporate administrative expenses and also includes business development expenses. In addition, the Corporate Segment contains our captive insurance company, WRM, through which we have elected to retain some of our operating risks. WRM provides our primary layer of property and casualty insurance in the United States. By using this insurance subsidiary, we have reduced the cost of our property and casualty insurance premiums and retained some economic benefits due to our excellent loss record. We reduce our major exposure by insuring for losses in excess of our retained limits with a number of third-party insurance companies.
Available Information
We file annual, quarterly and current reports, proxy statements and other information with the SEC. You may access and read our filings without charge through the SEC’s website, at www.sec.gov. You may also read and copy any document we file at the SEC’s public reference room located at 100 F Street, N.E., Room 1580, Washington, D.C. 20549. Please call the SEC at 1-800-SEC-0330 for further information regarding the operation of its public reference room.
We also make our public reports available, free of charge, through our website, www.westmoreland.com, as soon as practicable after we file or furnish them with the SEC. You may also request copies of the documents, at no cost, by telephone at (303) 992-6463 or by mail at Westmoreland Coal Company, 9540 South Maroon Circle, Suite 200, Englewood, Colorado, 80112. The information on our website is not part of this Annual Report on Form 10-K.
ITEM 1A
ITEM 1A
- RISK FACTORS.
This report, including Management’s Discussion and Analysis of Financial Condition and Results of Operation, contains forward-looking statements that may be materially affected by numerous risk factors, including those summarized below.
Risks Relating to our Business and Operations
Long-term sales and revenues could be significantly affected by environmental regulations and the effects of the environmental lobby.
Environmental regulations that are becoming increasingly stringent, as well as increased pressure from environmental activists, may reduce demand for our products. For example, a consortium of environmental activists is actively pushing to shut down one-third of the US coal plants by 2020. They are taking particular interest in Colstrip Units 1 and 2 and are actively lobbying the EPA to require cost-prohibitive pollution control equipment. In litigation filed in 2012, the activists stated that the EPA’s Best Available Retrofit Technology (“BART”) analysis for regional haze provides support for a determination that additional controls are necessary to achieve BART in the State of Montana. In June of 2015, the U.S. Court of Appeals for the Ninth Circuit found that EPA had failed to adequately explain its decision to require less stringent emission control technology for nitrogen oxides at Colstrip, and vacated the BART analysis and remanded it to the EPA for further proceedings. The EPA has not yet taken any action on a new regional haze plan. In 2013, environmental groups also filed a citizen suit complaint in Montana district court asserting that the owners and operators of Colstrip are in violation of Clean Air Act requirements. Trial in the case has been reset for May 2016. If environmental groups are successful, Colstrip would be required to undergo new permitting and comply with more stringent emission limits applicable to a number of pollutants. If additional emissions controls and upgrades are required at Colstrip Units 1 and 2, it is possible the owners could elect to shut down the units in lieu of making the large capital expenditures required to comply. If such a decision were made, we could lose coal sales of approximately 3.0 million tons per year. The loss of the sale of this tonnage at our Colstrip Mine could have a material adverse effect on the mine’s revenues and profitability.
Additionally, Rocky Mountain Power, the owner of the Naughton Power Station located adjacent to our Kemmerer Mine, which is our Kemmerer Mine’s primary customer, has sought regulatory approval to convert Unit 3 at Naughton to 100% natural gas fueling. When complete, the conversion of Unit 3 to natural gas will result in the loss of coal sales at our Kemmerer Mine. However, Rocky Mountain Power recently announced the conversion of Naughton Unit 3 will not occur until 2018. In addition, price protections built into the contract that are in effect from 2017 to 2021 will partially offset the effects of lowered volume following the conversion of Unit 3. Despite these price protections, the lost sales at the Kemmerer Mine could have a material adverse effect on the mine’s revenues and profitability and on our operating results. Additional power plants that buy our coal may be considering or may consider in the future fuel source conversion or decreased operations in order to avoid costly upgrades of pollution control equipment, and such steps, if taken, could result in a reduced demand for our products and materially and adversely affect our revenues and profitability.
In May 2015, the EPA and the U.S. Army Corps of Engineers issued a final rule to clarify which waters and wetlands are subject to regulation under the CWA. The implementation of this rule was stayed nationwide in October 2015. A change in CWA jurisdiction and permitting requirements could increase or decrease our permitting and compliance costs.
The EPA has executed a final rule relating to the disposal of CCR from electric utilities. The changes to the management of CCR could increase our and our customers’ operating costs and reduce sales of coal.
We are also affected by Canadian GHG emissions regulations. On September 12, 2012, the federal government of Canada released final regulations for reducing GHG emissions from coal-fired electricity generation: “Reduction of Carbon Dioxide Emissions from Coal-Fired Generation of Electricity” (the “Canadian CO2 Regulations”). The Canadian CO2 Regulations required certain Canadian coal-fired electricity generating plants, effective July 1, 2015, to achieve an average annual emissions intensity performance standard of 463 tons of CO2 per gigawatt hour. The impact of the Canadian CO2 Regulations on existing plants will vary by province and specific location. The Prairie Operation’s long-term sales could be reduced unless certain existing plants that it supplies or new plants built to replace such existing plants are equipped with carbon capture and sequestration or other technology that achieves the prescribed performance standard, the impact of the Canadian CO2 Regulations is altered by equivalency agreements, or the Canadian CO2 Regulations are changed to lower the performance standard.
In addition, various Canadian provincial governments and other regional initiatives are moving ahead with GHG reduction and other initiatives designed to address climate change. As it is unclear at this time what shape additional regulation in Canada will ultimately take, it is not yet possible to reliably estimate the extent to which such regulations will impact the operations we acquired in the Canadian Acquisition. However, our Canadian Operations involve large facilities, so the setting
of emissions targets (whether in the manner described above or otherwise) may well affect some or all of our Canadian customers, and may in turn have a material adverse effect on our business, results of operations and financial performance. In addition to directly emitting GHGs, our Canadian Operations require large quantities of power. Future taxes on or regulation of power producers or an increase in cost of the fuels used in power production (including coal, oil and gas or other products) may also add to our operating costs.
We have a substantial amount of indebtedness, which may adversely affect our cash flow and our ability to operate our business.
We have a substantial amount of indebtedness. At December 31, 2015, we had a total outstanding indebtedness of approximately $1,046 million, including (i) $350 million in principal amount of 8.75% Notes, (ii) $327.2 million in principal amount under the WCC Term Loan Facility, (iii) $299.2 million WMLP Term Loan and (iv) $19.8 million of supported letters of credit under the WCC Revolving Credit Facility, respectively, leaving $28.2 million of undrawn availability thereunder. Our substantial amount of indebtedness could have important consequences. For example, it could:
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increase our vulnerability to adverse economic, industry or competitive developments;
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result in an event of default if we fail to satisfy our obligations with respect to the 8.75% Notes, the WCC Term Loan Facility, the WCC Revolving Credit Facility or other debt or fail to comply with the financial and other restrictive covenants contained in the 8.75% Notes, the WCC Term Loan Facility, the WCC Revolving Credit Facility Agreement or agreements governing our other indebtedness, which event of default could result in all of our debt becoming immediately due and payable and could permit our lenders to foreclose on our assets securing such debt or otherwise recover that debt from us;
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require a substantial portion of cash flow from operations to be dedicated to the payment of principal, premium, if any, and interest on our indebtedness, therefore reducing our ability to use our cash flow to fund our operations, capital expenditures and future business opportunities;
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make it more difficult for us to satisfy our obligations with respect to the 8.75% Notes, the WCC Term Loan Facility and the WCC Revolving Credit Facility;
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increase our cost of borrowing;
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restrict us from making strategic acquisitions or causing us to make non-strategic divestitures;
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limit our ability to service our indebtedness, including the 8.75% Notes, the WCC Term Loan Facility and the WCC Revolving Credit Facility;
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limit our ability to obtain additional financing for working capital, capital expenditures, debt service requirements, acquisitions and general corporate or other purposes;
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limit our flexibility in planning for, or reacting to, changes in our business or the industry in which we operate, placing us at a competitive disadvantage compared to our competitors who are less highly leveraged and who therefore may be able to take advantage of opportunities that our leverage prevents us from exploiting; and
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prevent us from raising the funds necessary to repurchase all 8.75% Notes tendered to us upon the occurrence of certain changes of control, which failure to repurchase would constitute a default under the 8.75% Notes.
The occurrence of any one of these events could have a material adverse effect on our business, financial condition, results of operations, prospects and our ability to satisfy our obligations under the 8.75% Notes, the WCC Term Loan Facility and the WCC Revolving Credit Facility.
In conjunction with our acquisition of the GP, WMLP entered into the WMLP Financing Agreement to refinance WMLP’s indebtedness. The WMLP Financing Agreement provides for up to $295 million of first priority secured term loans, with $175 million currently funded and maturing in December 2018. WMLP used its delayed draw availability of $120 million under the WMLP Financing Agreement to fund the Kemmerer Drop that took place on August 1, 2015. Additionally, there is an accordion feature that takes effect when the delayed draw term loan feature expires which makes a further $150 million available for use to fund acquisitions during the remaining three years until the maturity of the WMLP Loan. Although the WMLP Loan will be consolidated in our financial statements due to our ownership of the GP and controlling interest in WMLP, neither Westmoreland nor any of its restricted subsidiaries will be obligors under the WMLP Financing Agreement and the WMLP Loan will be non-recourse to Westmoreland and its wholly owned subsidiaries.
If we further increase our indebtedness, the related risks that we now face, including those described above, could intensify.
If we fail to comply with certain covenants in our various debt arrangements, it could negatively affect our liquidity and ability to finance our operations.
Our lending arrangements contain, among other terms, events of default and various affirmative and negative covenants. Should we be unable to comply with any future debt-related covenant, we will be required to seek a waiver of such covenant to avoid an event of default. Covenant waivers and modifications may be expensive to obtain, or, potentially, unavailable. If we are in breach of any covenant and are unable to obtain covenant waivers and our lenders accelerate our debt, we could attempt to refinance the debt or repay the debt by selling assets and applying the proceeds from such sales to the debt. Sales of assets undertaken in response to such immediate needs may be prohibited under our lending arrangements without the consent of our lenders, may be made at potentially unfavorable prices, or asset sales may not be sufficient to refinance or repay the debt, and we may be unable to complete such transactions in a timely manner, on favorable terms, or at all.
We may not generate sufficient cash flow at our operating subsidiaries to pay our operating expenses, meet our debt service costs and pay our heritage and corporate costs.
Our ability to fund our operations and to make scheduled payments on our indebtedness will depend on our ability to generate cash in the future. Our historical financial results have been, and we expect our future financial results to be, subject to substantial fluctuations, and will depend upon general economic conditions and financial, competitive, legislative, regulatory and other factors that are beyond our control. We may not be able to maintain a level of cash flow from operating activities sufficient to permit us to pay the principal and interest on the 8.75% Notes, the WCC Term Loan Facility or our other indebtedness.
If our cash flow and capital resources are insufficient to meet our debt service obligations or to fund our other liquidity needs, we may need to refinance all or a portion of our debt before maturity, seek additional equity capital, reduce or delay scheduled expansions and capital expenditures or sell material assets or operations. We cannot assure you that we would be able to refinance or restructure our indebtedness, obtain equity capital or sell assets or operations on commercially reasonable terms or at all. In addition, the terms of existing or future debt instruments may limit or prevent us from taking any of these actions. Our inability to take these actions and to generate sufficient cash flow to satisfy our debt service and other obligations could have a material adverse effect on our business, financial condition, results of operations and prospects.
If we cannot make scheduled payments on our debt or are not in compliance with our covenants and are not able to amend those covenants, we will be in default and holders of the 8.75% Notes and the lenders under the WCC Term Loan Facility and the WCC Revolving Credit Facility could declare all outstanding principal and interest to be due and payable, the lenders under the WCC Revolving Credit Facility could terminate their commitments to loan money to us, the holders of the 8.75% Notes and the lenders under the WCC Term Loan Facility and the WCC Revolving Credit Facility could foreclose on the assets securing our debt to them and we could be forced into bankruptcy or liquidation. If we are not able to generate sufficient cash flow from operations, we may need to seek an amendment to the 8.75% Notes, the WCC Term Loan Facility or the WCC Revolving Credit Facility to prevent us from potentially being in breach of our covenants. Such amendments, waivers or other modifications to our debt instruments may be expensive to obtain or potentially unavailable. If we are unable to obtain such an amendment, waiver or other modification, and our lenders accelerate our debt, we could attempt to refinance the debt or repay the debt by selling assets and applying the proceeds from such sales to the debt. Sales of assets undertaken in response to such immediate needs may be prohibited under our lending arrangements without the consent of our lenders, may be made at potentially unfavorable prices, or asset sales may not be sufficient to refinance or repay the debt, and we may be unable to complete such transactions in a timely manner, on favorable terms, or at all.
As a mine mouth operator, we provide coal to a small group of customers. This dependence could adversely affect our revenues if such customers reduce or suspend their coal purchases or if they become unable to pay for our coal.
In 2015, our Coal - U.S. Segment derived approximately 75% of its total revenues from coal sales to five power plants: Colstrip Units 3&4 (26%); Limestone Generating Station (16%); American Electric Power Company, Inc. (13%), Colstrip Units 1&2 (11%); and Pacificorp Energy, Inc. (9%). Our Coal - Canada Segment derived approximately 80% of its total revenues from coal sales to two customers and one country: SaskPower (42%), the country of Japan (22%) and ATCO Power (17%). WMLP derived approximately 58% of its total coal revenues from sales to two customers: American Electric Power Company, Inc. (42%) and Pacificorp Energy, Inc. (16%). A portion of these sales were facilitated by coal brokers. Interruption in the purchases of coal by our principal customers could significantly affect our revenues.
Unscheduled maintenance outages or other outages at our customers’ power plants, unseasonably moderate weather, higher-than-anticipated hydro seasons or increases in the production of alternative clean-energy generation such as wind power, or decreases in the price of competing fossil fuels such as natural gas, could cause our customers to reduce their purchases. Ten of our 12 mines are dedicated to supplying customers located adjacent to or near the mines, and these mines may have difficulty identifying alternative purchasers of their coal if their existing customers suspend or terminate their purchases.
Additionally, certain of our long-term contracts are set to expire in the next several years. Our contracts with the Sherburne County Station are three-year rolling contracts, with one-third of the tonnage expiring on an annual basis. We have no tons under contract at this station after 2016. Our contract with Coyote Station, located adjacent to our Beulah mine and averaging approximately 2.5 million tons of coal sold per year, expires in May 2016 and is not expected to be renewed. Our contract with Colstrip Units 3 & 4 expires in December 2019. Should we be unable to successfully renew any or all of these expiring contracts, the reduction in the sale of our coal would adversely affect our operating results and liquidity and could result in significant impairments to the affected mine should the mine be unable to execute a new long-term coal supply agreement. The long term agreements we acquired or subsequently negotiated in connection with the Canadian Acquisition have long-remaining terms. Coal supply agreements also typically contain force majeure provisions allowing temporary suspension of performance by us or the customer during the duration of specified events beyond the control of the affected party. Such agreements may also prohibit us from passing certain increased costs resulting from changes in regulations to our customers. Additionally, many of our coal supply agreements contain provisions allowing customers to suspend acceptance of coal shipments if coal delivered does not meet certain quality thresholds.
Similarly, interruption in the purchase of power by DNCP could also negatively affect our revenues. During the year ended December 31, 2015, the sale of power by ROVA to DNCP accounted for approximately 6% of our consolidated revenues. Although ROVA supplies power to DNCP under long-term power purchase agreements, if DNCP is unable or unwilling to pay for the power produced by ROVA in a timely manner, it could have a material adverse effect on our results of operations, financial condition, and liquidity.
WMLP also sells a material portion of its coal under supply contracts. For the year ended December 31, 2015, approximately 87% of WMLP's coal production was sold under long-term supply contracts. When WMLP’s current contracts with customers expire, its customers may decide not to extend existing contracts or enter into new contracts. In 2015, 1.7 million tons are to be priced based on market indices, and from 2016 to 2018, 2.4 million tons are dependent upon reaching agreement during reopener periods.
Price adjustment, “price re-opener” and other similar provisions in WMLP’s supply contracts may reduce the protection from short-term coal price volatility traditionally provided by such contracts. Price re-opener provisions typically require the parties to agree on a new price. Failure of the parties to agree on a price under a price re-opener provision can lead to termination of the contract. Any adjustment or renegotiations leading to a significantly lower contract price could adversely affect WMLP’s business, financial condition and/or results of operations.
In the absence of long-term contracts, WMLP’s customers may decide to purchase fewer tons of coal than in the past or on different terms, including different pricing terms. Negotiations to extend existing contracts or enter into new long-term contracts with those and other customers may not be successful, which would negatively affect WMLP’s ability to have sufficient cash to pay distributions and, in turn, would negatively affect our cash flow.
Our hedging arrangement related to our ROVA facility may continue to result in losses when the market price for power drops below the level of our hedged position and, under certain circumstances, requires us to post additional collateral.
The Consolidated Agreement with respect to our ROVA facility provides for the sale to DNCP and its affiliates of all of ROVA’s net electrical output and dependable capacity. The Consolidated Agreement permits Westmoreland Partners to mitigate its cash losses through the sale to DNCP of fixed-price purchased power, during periods when it is uneconomical to operate the ROVA units. Under the Consolidated Agreement, we forego dispatching the ROVA units in low demand periods and maintain them in idle status. During such low demand periods, we meet DNCP’s power needs with fixed-price purchased power when doing so is more economically attractive than our physically operating the ROVA plants to generate power. Alternatively, we operate the ROVA plants, sell our produced power to DNCP and resell the fixed-price purchased power in the open market. When we operate the ROVA plants and resell our fixed-price purchased power into the open market, any such resales are made at prevailing market rates. In the event that the prevailing market price for power falls below the level of our hedged position during periods when we are reselling the fixed-price purchased power in the open market, those resales result in losses to us. During 2015, we incurred losses related to these hedging arrangements of $5.6 million. Based on current market pricing trends, we expect to experience losses from time to time under these hedging arrangements when the market price for power is not commensurate with our hedged position.
Further, we are required to post collateral to cover certain projected long-term losses under these hedging arrangements based on the market price for power. The amount of such collateral may be significant and may negatively impact our liquidity.
Our ability to collect payments from our customers could be impaired if their creditworthiness deteriorates.
Our ability to receive payment for coal sold and delivered depends on the continued creditworthiness of our customers. If we determine that a customer is not creditworthy, we may not be required to deliver coal under the customer’s coal sales contract. If this occurs, we may decide to sell the customer’s coal on the spot market, which may be at prices lower than the contracted price, or we may be unable to sell the coal at all. Furthermore, the bankruptcy of any of our customers could materially and adversely affect our financial position. In addition, competition with other coal suppliers could cause us to extend credit to customers and on terms that could increase the risk of payment default.
In addition, WMLP sells some of its coal to brokers who may resell its coal to end users, including utilities. These coal brokers may have only limited assets, making them less creditworthy than the end users. Under some of these arrangements, WMLP has contractual privity only with the brokers and may not be able to pursue claims against the end users. The bankruptcy or financial deterioration of any of WMLP’s customers, whether an end user or a broker, could negatively affect WMLP's ability to have sufficient cash to pay distributions and, in turn, would negatively affect our cash flow.
Volatility in the equity markets or interest rate fluctuations could substantially increase our pension funding requirements and negatively impact our financial position.
At December 31, 2015, the projected benefit obligation under our defined benefit pension plans was $181.4 million and the fair value of plan assets was $141.1 million. The difference between plan obligations and assets, or the funded status of the plans, significantly affects the net periodic benefit cost and ongoing funding requirements of those plans. Among other factors, changes in interest rates, mortality rates, early retirement rates, investment returns and the market value of plan assets can affect the level of plan funding, cause volatility in the net periodic benefit cost and increase our future funding requirements. During the fiscal year ended 2015, we made $3.7 million in contributions to these pension plans and accrued $0.2 million in expenses related thereto. The current economic environment increases the risk that we may be required to make even larger contributions in the future.
If our assumptions regarding our future expenses related to employee benefit plans are incorrect, then expenditures for these benefits could be materially higher than we have assumed. In addition, we may have exposure under those plans that extend beyond what our obligations would be with respect to our own employees.
We provide various postretirement medical benefits and workers’ compensation benefits to current and former employees and their dependents. We calculate the total accumulated benefit obligations according to guidance provided by U.S. Generally Accepted Accounting Principles ("GAAP"). We estimate the present value of our postretirement medical, black lung and workers’ compensation benefit obligations to be $299.4 million, $17.8 million and $5.7 million, respectively, at December 31, 2015. In respect of our Canadian Operations we have an obligation to provide postretirement health coverage for eligible current union employees, as described in greater detail below. We have estimated these unfunded obligations based on actuarial assumptions and if our assumptions do not materialize as expected, cash expenditures and costs that we incur could be materially different.
Moreover, regulatory changes could increase our obligations to provide these or additional benefits. We participate in defined benefit multi-employer funds that were established in connection with the Coal Act, which provides for the funding of health and death benefits for certain UMWA retirees. Our contributions to these funds totaled $1.8 million and $2.0 million for the years ended December 31, 2015 and 2014, respectively. Our contributions to these funds could increase as a result of a shrinking contribution base as a result of the insolvency of other coal companies that currently contribute to these funds, lower than expected returns on fund assets or other funding deficiencies.
We could also have obligations under the Tax Relief and Health Care Act of 2006, (“2006 Act”). The 2006 Act authorized up to a maximum of $490 million in federal contributions to pay for certain benefits, including the healthcare costs under certain funds created by the Coal Act for “orphans,” i.e. retirees from companies that subsequently ceased operations, and their dependents. However, if Congress were to amend or repeal the 2006 Act or if the $490 million authorization were insufficient to pay for these healthcare costs, we, along with other contributing employers and certain affiliates, would be responsible for the excess costs.
We also contribute to a multi-employer defined benefit pension plan, the Central Pension Fund of the Operating Engineers, ("Central Pension Fund") on behalf of employee groups at our Colstrip, Absaloka and Savage mines that are represented by the International Union of Operating Engineers. The Central Pension Fund is subject to certain funding rules contained in the Pension Protection Act of 2006 (“PPA”). Under the PPA, if the Central Pension Plan fails to meet certain minimum funding requirements, it would be required to adopt a funding improvement plan or rehabilitation plan. If the Central Pension Fund adopted a funding improvement plan or rehabilitation plan, we could be required to contribute additional amounts to the fund. As of January 31, 2015, its last completed fiscal year, the Central Pension Fund reported that it was underfunded. If we were to partially or completely withdraw from the fund at a time when the Central Pension Fund were
underfunded, we would be liable for a proportionate share of the fund’s unfunded vested benefits, and this liability could have a material adverse effect on our financial position.
Through our Canadian Operations we have responsibility for obligations under certain pension plans related to certain of the acquired operations. We have evaluated these plans, and believe that certain of them may be underfunded by immaterial amounts.
We are obligated to make contributions to these plans based upon agreement with the plan members and collective bargaining agreements with the representative unions. Our future contributions to these defined benefit plans are made in accordance with applicable pension legislation and the Income Tax Act (Canada). Further contributions to the pension plans could be required based on actuarial valuations, agreements, the plan asset investment performance, and future legislated requirements.
Under Canadian provincial Workers’ Compensation legislation, we remain obligated to fund workers’ compensation benefits arising from workplace injuries, disease and death of current and former employees. This obligation is based on premiums assessed by the applicable Workers’ Compensation Board which may vary based on the claims experience of the employer. We may be required to contribute additional premiums in the future depending on the number and amount of claims.
Our reserve estimates may prove to be incorrect.
The coal reserve estimates in this report are estimates based on the interpretation of limited sampling and subjective judgments regarding the grade, continuity and existence of mineralization, as well as the application of economic assumptions, including assumptions as to operating costs, foreign exchange rates and future commodity prices. The sampling, interpretations or assumptions underlying any reserve estimate may be incorrect, and the impact on the amount of reserves ultimately proven to be recoverable may be material. Should the mineralization and/or configuration of a deposit ultimately turn out to be significantly different from that currently envisaged, then the proposed mining plan may have to be altered in a way that could affect the tonnage and grade of the reserves mined and rates of production and, consequently, could adversely affect the profitability of the mining operations. In addition, short term operating factors relating to the reserves, such as the need for orderly development of ore bodies or the processing of new or different ores, may cause reserve estimates to be modified or operations to be unprofitable in any particular fiscal period. There can be no assurance that our projects or operations will be, or will continue to be, economically viable, that the indicated amount of minerals will be recovered or that they will be recovered at the prices assumed for purposes of estimating reserves.
Any inaccuracies in our estimates of our coal reserves could result in decreased profitability from lower than expected revenues or higher than expected costs.
Our future performance depends on, among other things, the accuracy of our estimates of our proven and probable coal reserves. Our reserve estimates are prepared by our engineers and geologists or by third-party engineering firms and are updated periodically. There are numerous factors and assumptions inherent in estimating the quantities and qualities of, and costs to mine, coal reserves, including many factors beyond our control, including the following:
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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.
We estimate that our gross reclamation and mine-closing liabilities, which are based upon projected mine lives, current mine plans, permit requirements and our experience, were $419.8 million (on a present value basis) at December 31, 2015. Of these December 31, 2015 liabilities, our customers have assumed $94.9 million by contract. In addition, we held final reclamation deposits, received from customers, of approximately $77.4 million at December 31, 2015 to provide for these obligations. We estimate that our obligation for final reclamation that was not the contractual responsibility of others or covered by offsetting reclamation deposits was $247.5 million at December 31, 2015. We must recover this $247.5 million from revenues generated by coal sales.
Although we update our estimated costs annually, our recorded obligations may prove to be inadequate due to changes in legislation or standards and the emergence of new restoration techniques. Furthermore, the expected timing of expenditures could change significantly due to changes in commodity costs or prices that might curtail the life of an operation. These recorded obligations could prove insufficient compared to the actual cost of reclamation. Any underestimated or unidentified close down, restoration or environmental rehabilitation costs could have an adverse effect on our reputation as well as our asset values, results of operations and liquidity.
If the cost of obtaining new reclamation bonds and renewing existing reclamation bonds increases or if we are unable to obtain additional bonding capacity, our operating results could be negatively affected.
We are required to provide bonds to secure our obligations to reclaim lands used for mining. We must post a bond before we obtain a permit to mine any new area. These bonds are typically renewable on a yearly basis. Bonding companies are requiring that applicants collateralize increasing portions of their obligations to the bonding company. We anticipate that, as we permit additional areas for our mines, our bonding and collateral requirements could increase. Any cash that we provide to collateralize our obligations to our bonding companies is not available to support our other business activities. Our results of operations could be negatively affected if the cost of our reclamation bonding premiums and collateral requirements were to increase. Additionally, if we are unable to obtain additional bonding capacity due to cash flow constraints, we will be unable to begin mining operations in newly permitted areas, which would hamper our ability to efficiently meet our current customer contract deliveries, expand operations, and increase revenues.
Our coal mining operations are subject to external conditions that could disrupt operations and negatively affect our results of operations.
With the exception of the Buckingham mine and the San Juan mine, our coal mining operations are all surface mines. These mines are subject to conditions or events beyond our control that could disrupt operations, affect production, and increase the cost of mining at particular mines for varying lengths of time. These conditions or events include: unplanned equipment failures; geological, hydrological or other conditions such as variations in the quality of the coal produced from a particular seam; variations in the thickness of coal seams and variations in the amounts of rock and other natural materials that overlie the coal that we are mining; weather conditions; and competition and/or conflicts with natural gas and other resource extraction activities and production within our operating areas. For example, we have endured poor rail performance at the Absaloka mine and Coal Valley mine, a major blizzard at the Beulah mine, a trestle fire at the Beulah mine, an unanticipated replacement of boom suspension cables on one of our draglines, all of which interrupted deliveries. Major disruptions in operations at any of our mines over a lengthy period could adversely affect the profitability of our mines.
In addition, unplanned outages of draglines and extensions of scheduled outages due to mechanical failures or other problems occur from time-to-time and are an inherent risk of our coal mining business. Unplanned outages typically increase our operation and maintenance expenses and may reduce our revenues because of selling fewer tons of coal. As of December 31, 2015, seven of our 31 owned or operated draglines were not in use due to either equipment servicing or because the dragline was scheduled to be down based on the operational needs of our mines. When properly maintained, a dragline can operate for 40 years or longer. As of December 31, 2015, the average age of Westmoreland’s dragline fleet was 35 years. As our
draglines, shovels and other major equipment age, we may experience unscheduled maintenance outages or increased maintenance costs, which would adversely affect our operating results.
Unplanned outages and extensions of scheduled outages due to mechanical failures or other problems occur from time to time at our power plant customers and are an inherent risk of our business. Unplanned outages typically increase our operation and maintenance expenses and may reduce our revenues because of selling fewer tons of coal. For example, the Conesville power plant, which is the largest customer of our Buckingham mine, experienced an unexpected shutdown in the first and second quarters of 2015. The plant was brought back into operation in the third quarter of 2015, but was subsequently taken back out of production to address vibration issues caused by a malfunctioning fan in one of the units. The Conesville plant ran at half its capacity until the necessary repairs were completed in early December 2015. We maintain business interruption insurance coverage at some of our mines to lessen the impact of events such as this. However, business interruption insurance may not always provide adequate compensation for lost coal sales, and significant unanticipated outages at our power plant customers which result in lost coal sales could result in significant adverse effects on our operating results. Additionally, our Beulah mine filed an intercompany business interruption claim with WRI, our captive insurance subsidiary, in the second quarter of 2015, which resulted in an increase in operating expenses in our Corporate Segment.
Our operations are vulnerable to natural disasters, operating difficulties and infrastructure constraints, not all of which are covered by insurance, which could have an impact on our productivity.
Mining and power operations are vulnerable to natural events, including blizzards, earthquakes, drought, floods, fire, storms and the possible effects of climate change. Operating difficulties such as unexpected geological variations could affect the costs and viability of our operations. Our operations also require reliable roads, rail networks, power sources and power transmission facilities, water supplies and IT systems to access and conduct operations. The availability and cost of infrastructure affects our capital expenditures, operating costs, and planned levels of production and sales.
We maintain insurance for some, but not all, of the potential risks and liabilities associated with our business. For some risks, we may not obtain insurance if we believe the cost of available insurance is excessive relative to the risks presented. As a result of market conditions, premiums and deductibles for certain insurance policies can increase substantially, and in some instances, certain insurance may become unavailable or available only for reduced amounts of coverage. As a result, we may not be able to renew our existing insurance policies or procure other desirable insurance on commercially reasonable terms, if at all. Although we maintain insurance at levels we believe are appropriate and consistent with industry practice, we are not fully insured against all risks. In addition, pollution and environmental risks and consequences of any business interruptions such as equipment failure or labor disputes generally are not fully insurable. Losses and liabilities from uninsured and underinsured events and delay in the payment of insurance proceeds could have a material adverse effect on our financial condition, results of operations and cash flows.
Mining in Northern Appalachia and the Illinois Basin is more complex and involves more regulatory constraints than mining in other areas of the United States.
The geological characteristics of Northern Appalachian and Illinois Basin coal reserves, such as depth of overburden and coal seam thickness, make them complex and costly to mine. As WMLP’s mines in these regions become depleted, replacement reserves may not be available when required or, if available, may not be capable of being mined at costs comparable to those of the depleting mines. These factors could adversely affect WMLP’s business, financial condition and/or results of operations and its ability to make distributions to unit holders like us.
A defect in title or the loss of a leasehold interest in certain property could limit our ability to mine our coal reserves or result in significant unanticipated costs.
We conduct a significant part of our coal mining operations on properties that we lease. A title defect or the loss of a lease could adversely affect our ability to mine the associated coal reserves. We may not verify title to our leased properties or associated coal reserves until we have committed to developing those properties or coal reserves. We may not commit to develop property or coal reserves until we have obtained necessary permits and completed exploration. As such, the title to property that we intend to lease or coal reserves that we intend to mine may contain defects prohibiting our ability to conduct mining operations. Similarly, our leasehold interests may be subject to superior property rights of other third parties. In order to conduct our mining operations on properties where these defects exist, we may incur unanticipated costs. In addition, some leases require us to produce a minimum quantity of coal and require us to pay minimum production royalties. Our inability to satisfy those requirements may cause the leasehold interest to terminate.
We are dependent on information technology and our systems and infrastructure face certain risks, including cybersecurity risks and data leakage risks.
We are dependent on information technology systems and infrastructure. Any significant breakdown, invasion, destruction or interruption of these systems by employees, others with authorized access to our systems, or unauthorized persons could negatively impact operations. There is also a risk that we could experience a business interruption, theft of information, or reputational damage as a result of a cyber-attack, such as an infiltration of a data center, or data leakage of confidential information either internally or at our third-party providers. While we have invested in the protection of our data and information technology to reduce these risks and periodically test the security of our information systems network, there can be no assurance that our efforts will prevent breakdowns or breaches in our systems that could adversely affect our business.
Our Absaloka mine benefited from Indian Coal Production Tax Credits. Our inability to execute a new agreement with a new partner will adversely affect the financial condition of the operation.
The ICTC, which our Absaloka mine historically benefited from, expired on December 31, 2014, and was renewed on December 18, 2015, expiring on December 31, 2016. We are seeking a new partner, but our results of operations will continue to be negatively affected during the interim period in which we do not have a partner to capitalize on the currently enacted ICTC. From 2009 through 2013, we experienced a yearly average of $3.1 million of income and $6.1 million of cash receipts from Absaloka’s participation in ICTC transactions.
Our future success depends upon our ability to continue acquiring and developing coal reserves that are economically recoverable and to raise the capital necessary to fund our expansion.
Our recoverable reserves decline as we produce coal. We have not yet applied for the permits to use all of the coal deposits under our mineral rights, and the government agencies may not grant those permits in a timely manner or at all. Furthermore, we may not be able to mine all of our coal deposits as efficiently as we do at our current operations. Our future success depends upon conducting successful exploration and development activities and acquiring properties containing economically recoverable coal deposits. Our current strategy includes increasing our coal reserves through acquisitions of other mineral rights, leases, or producing properties and continuing to use our existing properties. Our ability to expand our operations may be dependent on our ability to obtain sufficient working capital, either through cash flows generated from operations, or financing activities, or both. As we mine our coal and deplete our existing reserves, replacement reserves may not be available when required or, if available, we may not be capable of mining the coal at costs comparable to those characteristic of the depleting mines. These factors could have a material adverse effect on our mining operations and costs, and our customers’ ability to use the coal we mine.
We may not be able to successfully replace our reserves or grow through future acquisitions.
In recent years, we have expanded our operations by adding new mines and reserves through strategic acquisitions, and we intend to continue expanding our operations and coal reserves through additional future acquisitions. Our future growth could be limited if we are unable to continue making acquisitions, or if we are unable to successfully integrate the companies, businesses or properties we acquire. We may not be successful in consummating any acquisitions and the consequences of undertaking these acquisitions are unknown. Our ability to make acquisitions in the future could be limited by restrictions under our existing or future debt agreements, competition from other coal companies for attractive properties or the lack of suitable acquisition candidates.
Our cash flow depends, in part, on the available cash and distributions of WMLP.
We expect our partnership interests in WMLP to be significant cash-generating assets. Therefore, our cash flow will be dependent, to some extent, upon the ability of WMLP to make quarterly distributions to its unitholders, including us. WMLP may not have sufficient available cash each quarter to enable it to pay distributions, which would have a corresponding negative impact on us. The amount of cash WMLP can distribute on its units principally depends upon the amount of cash it generates from its operations, which will fluctuate from quarter to quarter based on, among other things:
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the domestic and foreign supply and demand for coal;
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the quantity and quality of coal available from competitors;
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the prices under WMLP’s existing contracts where the pricing is tied to and adjusted periodically based on indices reflecting current market pricing;
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competition for production of electricity from non-coal sources, including the price and availability of alternative fuels;
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domestic air emission standards for coal-fueled power plants and the ability of coal-fueled power plants to meet these standards by installing scrubbers or other means;
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adverse weather, climate or other natural conditions, including natural disasters;
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domestic and foreign taxes;
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domestic and foreign economic conditions, including economic slowdowns;
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legislative, regulatory and judicial developments, environmental regulatory changes or changes in energy policy and energy conservation measures that would adversely affect the coal industry, such as legislation limiting carbon emissions or providing for increased funding and incentives for alternative energy sources;
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the proximity to, capacity of and cost of transportation and port facilities;
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market price fluctuations for sulfur dioxide emission allowances;
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the level of capital expenditures it makes;
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the cost of acquisitions;
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its debt service requirements and other liabilities;
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fluctuations in its working capital needs;
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its ability to borrow funds and access the capital markets;
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restrictions contained in the debt agreements to which it is a party; and
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the amount of cash reserves established by its general partner.
Any adverse change in these and other factors could result in a decline in WMLP’s ability to have sufficient cash to pay distributions and, in turn, would negatively affect our cash flow.
Our tax position may be adversely affected by virtue of our interest in WMLP.
Our investment in WMLP may adversely affect our tax position. Whether or not WMLP makes cash distributions to us, we will have income from our interest in WMLP, which may or may not be offset by deductions from WMLP and may or may not be sufficient to fund the taxes on such income. Further, if WMLP has taxable income, we may be allocated a significant portion of that taxable income. Additionally, if the Internal Revenue Service ("IRS") successfully contests the positions that WMLP takes, the results of that contest may result in additional taxable income being allocated to us. We could also be subject to additional taxation by individual states in which we do not conduct business or have assets due to our investment in WMLP.
Our acquisition of the general partner of a publicly traded limited partnership may subject us to a greater risk of liability than ordinary business operations.
We own the general partner of WMLP, a publicly traded limited partnership. The general partner of WMLP may be deemed to have undertaken fiduciary obligations with respect to WMLP and its limited partners. Such fiduciary obligations may require a higher standard of conduct than ordinary business operations and, therefore, may involve a greater risk of liability, particularly when a conflict of interest is found to exist. Our control of the general partner of WMLP may increase the possibility of claims of breach of fiduciary duties, including claims brought due to conflicts of interest. Any liability resulting from such claims could be material.
Although we control WMLP through our ownership of the GP, the GP owes fiduciary duties to WMLP’s unitholders, which may conflict with the interests of our shareholders.
Conflicts of interest exist and may arise in the future as a result of the relationships between us and our affiliates, on the one hand, and WMLP and its limited partners, on the other hand. The directors and officers of the GP have fiduciary duties to manage WMLP in a manner beneficial to us, as the sole member of the GP. At the same time, the GP has fiduciary duties to manage the limited partnership in a manner beneficial to WMLP and its limited partners. The board of directors of the GP, and in certain cases the conflicts committee of the board, will resolve any such conflict and has broad latitude to consider the interests of all parties to the conflict. The resolution of these conflicts may not always be in our best interest. For example, conflicts of interest with WMLP may arise in the following situations:
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the interpretation and enforcement of contractual obligations between us and our affiliates, on the one hand, and WMLP, on the other hand;
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the determination of the amount of cash to be distributed to WMLP’s limited partners and the amount of cash to be reserved for the future conduct of WMLP’s business; and
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the determination whether to make borrowings under the WMLP Revolving Credit Facility to pay distributions to its limited partners.
In addition, subject to certain conditions, the 8.75% Notes, the WCC Term Loan Facility and the WCC Revolving Credit Facility permit us to transfer certain assets, including in certain instances equity interests we hold in other entities, to WMLP and its subsidiaries. Provided that we comply with the applicable conditions, we may transfer a significant portion of
our assets to WMLP and its subsidiaries, which will not be restricted subsidiaries or guarantors under the 8.75% Notes, WCC Term Loan Facility or borrowers under the WCC Revolving Credit Facility.
Because we own a controlling interest in WMLP, any internal control deficiencies at WMLP could impact our ability to accurately report our financial results or prevent fraud.
Effective internal controls are necessary for us to provide reliable financial reports and effectively prevent fraud. Because of inherent limitations, internal control over financial reporting may not prevent or detect misstatements. The consummation of the WMLP transactions expanded Westmoreland by adding a significant subsidiary with separate financial reporting. The addition of WMLP’s financial reporting may have adverse effects on our internal control over financial reporting.
The ongoing oversight of the operations of WMLP following the WMLP transactions could create additional risks to our disclosure controls that we may not foresee. WMLP is a separate, publicly traded master limited partnership, or MLP. However, due to our significant equity ownership in WMLP and ownership of the GP, we consolidate the results of WMLP in our public financial statements. To the extent WMLP’s internal control systems are deficient, the integrity of our financial statements and results could be affected and we could fail to meet our regulatory reporting obligations in a timely manner, which ultimately could harm our operating results.
Transportation impediments may hinder our current operations or future growth.
Certain segments of our current business, principally our Absaloka Mine and our Coal Valley Mine rely on rail transportation for the delivery of coal product to customers and ports. Our ability to deliver our product in a timely manner could be adversely affected by the lack of adequate availability of rail capacity, whether because of work stoppages, union work rules, track conditions or otherwise. In 2011, flooding conditions disrupted rail service to the Absaloka Mine, resulting in lost revenue. Rail or shipping transportation costs represent a significant portion of the total cost of coal for our customers, and the cost of transportation is a key factor in a customer’s purchasing decision. In addition, the Coal Valley Mine exports the majority of its production to the global seaborne market through a port facility in western Canada.
The unavailability of rail capacity and port capacity could also hinder our future growth as we seek to sell coal into new markets. The current availability of rail cars is limited and at times unavailable because of repairs or improvements, or because of priority transportation agreements with other customers. Port capacity is also restricted in certain markets. If transportation is restricted or is unavailable, we may be unable to sell into new markets and, therefore, the lack of rail or port capacity would hamper our future growth. We currently have sufficient committed port capacity to operate our export business, and additional port capacity is expected to be constructed in western Canada in the future. However, increases in transportation costs or the lack of sufficient rail or port capacity or availability could make our coal less competitive, or could result in coal becoming a less competitive source of energy in general, which could lead to reduced coal sales and/or reduced prices we receive for the coal. Our inability to timely deliver product or fuel switching due to rising transportation costs could have a material adverse effect on our business, financial condition and results of operations.
In addition, WMLP depends upon barge, rail and truck systems to deliver coal to its customers. Disruptions in transportation services due to weather-related problems, mechanical difficulties, strikes, lockouts, bottlenecks, and other events could impair WMLP’s ability to supply coal to its customers. In recent years, the Commonwealth of Kentucky and the State of West Virginia have increased enforcement of weight limits on coal trucks on their public roads. It is possible that all states in which WMLP’s coal is transported by truck may modify their laws to limit truck weight limits. Such legislation and enforcement efforts could result in shipment delays and increased costs, which could have an adverse effect on WMLP’s ability to increase or to maintain production and could adversely affect its revenues.
Decreased availability or increased costs of key equipment and materials could impact our cost of production and decrease our profitability.
We depend on reliable supplies of mining equipment, replacement parts and materials such as explosives, diesel fuel, tires and magnetite. The supplier base providing mining materials and equipment has been relatively consistent in recent years, although there continues to be consolidation, which has resulted in a limited number of suppliers for certain types of equipment and supplies. Any significant reduction in availability or increase in cost of any mining equipment or key supplies could adversely affect our operations and increase our costs, which could adversely affect our operating results and cash flows.
In addition, the prices we pay for these materials are strongly influenced by the global commodities market. Coal mines consume large quantities of commodities such as steel, copper, rubber products, explosives and diesel and other liquid fuels. Some materials, such as steel, are needed to comply with regulatory requirements. A rapid or significant increase in the cost of these commodities could increase our mining costs because we have limited ability to negotiate lower prices, and in some cases, do not have a ready substitute.
Our long-term coal contracts are "cost protected" in that they typically contain either full pass-through of our costs or price escalation and adjustment provisions, pursuant to which the price for our coal may be periodically revised in line with broad economic indicators such as the consumer price index, commodity-specific indices such as the PPI-light fuel oils index, and/or changes in our actual costs.
WMLP enters into forward-purchase contract arrangements for a portion of its anticipated diesel fuel and explosive needs. Additionally, some of WMLP’s expected diesel fuel requirements are protected, in varying amounts, by diesel fuel escalation provisions contained in coal supply contracts with some of its customers, that allow for a change in the price per coal ton sold. Price changes typically lag the changes in diesel fuel costs by one quarter. While WMLP’s strategy provides it protection in the event of price increases to its diesel fuel, it may also prevent WMLP from the benefits of price decreases. If prices for diesel fuel decreased significantly below WMLP’s forward-purchase contracts, it would lose the benefit of any such decrease.
Our ability to acquire new permits and licenses in certain Canadian provinces may be affected by aboriginal rights.
Canadian courts have recognized that aboriginal peoples may have rights with respect to land used or occupied by their ancestors in the absence of treaties to address those rights. These aboriginal rights may vary from limited rights of use for traditional purposes to rights of title and will depend upon, among other things, the nature and extent of prior aboriginal use and occupation. Aboriginal peoples may also have rights under applicable treaties for harvesting and ceremonial purposes on Crown lands or lands to which they have rights of access. The provincial governments of Alberta and Saskatchewan, as well as the Canadian government, are required to consult with aboriginal peoples with respect to the granting of and the issuance or amendment of project authorizations, including approvals, permits and licenses. These requirements may affect the ability of our Canadian Operations to acquire new or amended operating approvals in these jurisdictions within a reasonable time frame, and may affect our development schedule and costs.
Union represented labor creates an increased risk of work stoppages and higher labor costs.
As of December 31, 2015, approximately 39% of our total U.S. workforce is represented by two labor unions, the International Union of Operating Engineers and the UMWA. Our unionized workforce is spread out amongst the majority of our surface mines. As a majority of our workforce is unionized, there may be an increased risk of strikes and other labor disputes, and our ability to alter labor costs is subject to collective bargaining. The collective bargaining agreement relating to the represented workforce at the Absaloka Mine expired on May 31, 2015 and was renegotiated through May 31, 2021. In 2012, we were successful in entering into agreements with our workforce at Savage, Kemmerer and Colstrip. If our Jewett Mine operations were to become unionized, we could be subject to additional risk of work stoppages, other labor disputes and higher labor costs, which could adversely affect the stability of production and our results of operations. We reached an agreement with the UMWA in December 2014 on a new collective bargaining agreement at the Beulah Mine to replace the existing agreement which expired on January 1, 2015. While strikes are generally a force majeure event in long-term coal supply agreements, thereby exempting the mine from its delivery obligations, the loss of revenue for even a short time could have a material adverse effect on our financial results.
Congress has proposed legislation to enact a law allowing workers to choose union representation solely by signing election cards, which would eliminate the use of secret ballots to elect union representation. While the impact is uncertain, if the government enacts this proposal into law, which would make it administratively easier to unionize, it may lead to more coal mines becoming unionized.
As of December 31, 2015, approximately 70% of our total Canadian workforce was represented by a labor union. There are labor agreements in place with one or more unions at each of the producing mines of our Canadian Operations, other than the Genesee Mine. If we are not successful in negotiating new labor agreements as they expire with any of the Canadian workforce unions or otherwise maintaining strong partnerships with them, it could result in labor disputes, work stoppages or higher labor costs, any of which could have an adverse effect on our business and results of operations.
When the Kemmerer Drop occurred, WMLP gained a partially unionized workforce. Now that WMLP's workforce is approximately 30% unionized, it could adversely affect its productivity and labor costs and increase the risk of work stoppages, all of which could adversely affect WMLP’s business, financial condition and/or results of operations.
We face intense competition to attract and retain employees.
We are dependent on retaining existing employees and attracting additional qualified employees to meet current and future needs. We face intense competition for qualified employees, and there can be no assurance that we will be able to attract and retain such employees or that such competition among potential employers will not result in increasing salaries. We rely on employees with unique skill sets to perform our mining operations, including engineers, mechanics and other highly skilled individuals. An inability to retain existing employees or attract additional employees, especially with mining skills and background, could have a material adverse effect on our business, cash flows, financial condition and results of operations.
As a result of the Canadian Acquisition, we are subject to foreign exchange risk as a result of exposures to changes in currency exchange rates between the U.S. and Canada.
As a result of the Canadian Acquisition, we face increased exposure to exchange rate fluctuations between the Canadian dollar and U.S. dollar. We realize a large portion of our revenues from sales made from the Canadian assets in Canadian dollars, and almost all of the expenses incurred by the Canadian assets are recognized in Canadian dollars. The exchange rate of the Canadian dollar to the U.S. dollar has been at or near historic highs in recent years but in the last quarter of 2014 and first quarter of 2015 weakened considerably and continued to weaken throughout 2015. If this weakening of the Canadian dollar in comparison to the U.S. dollar continues, earnings generated from our Canadian Operations will translate into reduced earnings in our consolidated statements of operations reported in U.S. dollars. In addition, our Canadian Subsidiaries also record certain accounts receivable and accounts payable, which are denominated in Canadian dollars. Foreign currency transactional gains and losses are realized upon settlement of these assets and obligations.
Fluctuations in the U.S. dollar relative to the Canadian dollar may make it more difficult to perform period-to-period comparisons of our reported results of operations. For purposes of accounting, the assets and liabilities of our Canadian Operations will be translated using period-end exchange rates, and the revenues and expenses of our Canadian Operations will be translated using average exchange rates during each period. Translation gains and losses are reported in accumulated other comprehensive loss as a component of stockholders’ equity.
Federal legislation could result in higher healthcare costs.
In March 2010, the Patient Protection and Affordable Care Act (the “PPACA”) was enacted, impacting our costs of providing healthcare benefits to our eligible active employees, with both short-term and long-term implications. In the short term, our healthcare costs could increase due to, among other things, an increase in the maximum age for covered dependents to receive benefits, changes to benefits for occupational disease related illnesses, the elimination of lifetime dollar limits per covered individual and restrictions on annual dollar limits per covered individual. In the long term, our healthcare costs could increase for these same reasons, as well as due to an excise tax on “high cost” plans, among other things. Implementation of this legislation is expected to extend through 2018.
Beginning in 2018, the PPACA will impose a 40% excise tax on employers to the extent that the value of their healthcare plan coverage exceeds certain dollar thresholds. We anticipate that certain governmental agencies will provide additional regulations or interpretations concerning the application of this excise tax. We will continue to evaluate the impact of the PPACA, including any new regulations or interpretations, in future periods.
Any increase in cost, as a result of legislation or otherwise, could adversely affect our business, financial condition and/or results of operations.
Certain federal income tax preferences currently available with respect to coal exploration and development may be eliminated in future legislation.
Among the changes contained in President Obama’s budget proposal (the “Budget Proposal”) is the elimination of certain key U.S. federal income tax preferences relating to coal exploration and development. The Budget Proposal would: (i) eliminate current deductions, the 60-month amortization period and the 10-year amortization period for exploration and development costs relating to coal and other hard mineral fossil fuels, (ii) repeal the percentage depletion allowance with respect to coal properties, (iii) repeal capital gains treatment of coal and lignite royalties and (iv) exclude from the definition of domestic production gross receipts all gross receipts derived from the production of coal and other hard mineral fossil fuels. The passage of any legislation effecting changes similar to those in the Budget Proposal in U.S. federal income tax laws could eliminate certain tax deductions that are currently available with respect to coal exploration and development, and any such change could increase our taxable income and negatively impact the value of an investment in our common stock.
Risk Factors Relating to the Coal and Power Industries
The risk of prolonged recessionary conditions could adversely affect our financial condition and results of operations.
Because we sell substantially all of our coal to electric utilities, our business and results of operations remain closely linked to demand for electricity. Recent economic uncertainty has raised the risk of prolonged recessionary conditions. Historically, global demand for basic inputs, including electricity production, has decreased during periods of economic downturn. If demand for electricity production decreases, our financial condition and results of operations could be adversely affected.
Competition in the North American coal industry may adversely affect our revenues and results of operations.
A few of our competitors in the North American coal industry are major coal producers who have significantly greater financial resources than we do. The intense competition among coal producers may impact our ability to retain or attract customers and may therefore adversely affect our future revenues and results of operations. Among other things, competitors could develop new mines that compete with our mines, have higher quality coal than our mines or build or obtain access to rail lines that would adversely affect the competitive position of our mines. The current restructuring of several North American coal producers may reduce our clarity into the competitive markets in which we sell coal for in the near term, and the long-term effect of such restructuring on our competitive position is unclear.
Any change in consumption patterns by utilities away from the use of coal could affect our ability to sell the coal we produce or the prices that we receive.
In addition to competing with other coal producers, we compete generally with producers of other fuels. In 2015, the electric utility industry accounted for the majority of coal consumption in the U.S. and Canada. The demand for electricity, environmental and other governmental regulations, and the price and availability of competing fuels for power plants such as nuclear, hydro, natural gas and fuel oil as well as alternative sources of energy affects the amount of coal consumed by the electric utility industry. A decrease in coal consumption by the electric utility industry could adversely affect the demand for, and price of, coal, which could negatively impact our results of operations and liquidity. We do not have contracts guaranteeing the purchase of fixed quantities of coal, so revenue can fall even though we have long-term contracts.
Some power plants are fueled by natural gas because of the relatively lower construction costs of such plants compared to coal-fired plants and because natural gas is a cleaner burning fuel. In addition, some states have adopted or are considering legislation that encourages domestic electric utilities to switch from coal-fired power generation plants to natural gas powered plants. Similar legislation has been implemented or is under consideration in several Canadian provinces. Passage of these and other state, provincial or federal laws or regulations limiting carbon dioxide emissions could result in fuel switching, from coal to other fuel sources, by purchasers of our coal. Such laws and regulations could also mandate decreases in carbon dioxide emissions from coal-fired power plants, impose taxes on carbon emissions or require certain technology to capture and sequester carbon dioxide from coal-fired power plants. If these or similar measures are ultimately imposed by federal, state or provincial governments or pursuant to international treaty, our reserves and operating costs may be materially and adversely affected. Similarly, alternative fuels (non-fossil fuels) could become more attractive than coal in order to reduce carbon emissions, which could result in a reduction in the demand for coal and, therefore, our revenues.
Recently, the supply of natural gas has reached record highs and the price of natural gas has remained at depressed levels for sustained periods due to extraction techniques involving horizontal drilling and hydraulic fracturing that have led to economic access to large quantities of natural gas in the United States and Canada, making it an attractive competing fuel. A continuing decline in the price of natural gas, or continuing periods of sustained low natural gas prices, could cause demand for coal to decrease, result in fuel switching and decreased coal consumption by electricity-generating utilities and adversely affect the price of our coal. Sustained low natural gas prices may cause utilities to phase-out or close existing coal-fired power plants or reduce construction of any new coal-fired power plants, which could have a material adverse effect on demand and prices received for our coal.
Changes in the export and import markets for coal products could affect the demand for our coal, our pricing and our profitability.
Although our mines and the majority of our customers are located in North America, we compete in a worldwide market for coal and coal products. The pricing and demand for our products is affected by a number of global economic factors that are beyond our control and difficult to predict. These factors include:
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currency exchange rates;
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growth of economic development;
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price of alternative sources of electricity or steel;
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worldwide demand for coal and other sources of energy; and
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ocean freight rates.
Any decrease in the aggregate amount of coal exported from the United States and Canada, or any increase in the aggregate amount of coal imported into the United States and Canada, could have a material adverse impact on the demand for our coal, our pricing and our profitability. Ongoing uncertainty in European economies and slowing economies in China, India and Brazil have reduced and may continue to reduce near-term pricing and demand for coal exported from the United States and Canada. Coal Valley Mine primarily supplies premium thermal coal to the Asian export market. Ownership of this mine will increase our exposure to price fluctuations in the international coal market, and a substantial downturn in demand in the Asian market could have a material adverse effect on our financial condition and results of operations.
Extensive government regulations impose significant costs on our mining operations, and future regulations could increase those costs or limit our ability to produce and sell coal.
The coal mining industry is subject to increasingly strict regulation by federal, state and local authorities with respect to matters such as:
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limitations on land use;
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employee health and safety;
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mandated benefits for retired coal miners;
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mine permitting and licensing requirements;
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reclamation and restoration of mining properties after mining is completed;
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air quality standards;
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discharges to water;
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construction and permitting of facilities required for mining operations, including valley fills and other structures constructed in water bodies and wetlands;
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protection of human health, plant life and wildlife;
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management of the materials generated by mining operations and discharge of these materials into the environment;
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effects of mining on groundwater quality and availability; and
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remediation of contaminated soil, surface and groundwater.
We are required to prepare and present to governmental authorities data concerning the potential effects of any proposed exploration or production of coal on the environment and the public has statutory rights to submit objections to requested permits and approvals. Failure to comply with MSHA regulations may result in the assessment of administrative, civil and criminal penalties. Other governmental agencies may impose cleanup and site restoration costs and liens, issue injunctions to limit or cease operations, suspend or revoke permits and take other enforcement measures that could have the effect of limiting production from our operations. We may also incur costs and liabilities resulting from claims for damages to property or injury to persons arising from our operations. We must compensate employees for work-related injuries. If we do not make adequate provision for our workers’ compensation liabilities, it could harm our future operating results. If we are pursued for any sanctions, costs and liabilities, our mining operations and, as a result, our results of operations, could be adversely affected.
United States and Canadian federal, state or provincial regulatory agencies have the authority to temporarily or permanently close a mine following significant health and safety incidents, such as a fatality. In the event that these agencies order the closing of our mines, our coal sales contracts may permit us to issue force majeure notices which suspend our obligations to deliver coal under these contracts. However, our customers may challenge our issuances of force majeure notices. If these challenges are successful, we may have to purchase coal from third-party sources, if it is available, and potentially at prices higher than our cost to produce coal, to fulfill these obligations, and negotiate settlements with customers, which may include price and quantity reductions, the extension of time for delivery, or contract termination. Additionally, we may be required to incur capital expenditures to re-open the mine. These actions could adversely affect our business, financial condition and/or results of operations.
New legislation or regulations and orders may be adopted that may materially adversely affect our mining operations, our cost structure or our customers’ ability to use coal. New legislation or administrative regulations (or new judicial interpretations or administrative enforcement of existing laws and regulations), including proposals related to the protection of the environment that would further regulate and tax the coal industry, may also require us or our customers to change operations significantly or incur increased costs. These regulations, if proposed and enacted in the future, could have a material adverse
effect on our financial condition and results of operations. For additional information regarding specific regulations that impact our operations, see “Material Effects of Regulation - U.S. Regulation" and "Material Effects of Regulation - Canada Regulation."
Concerns regarding climate change are, in many of the jurisdictions in which we operate, leading to increasing interest and in some cases enactment of, laws and regulations governing greenhouse gas emissions, which affect the end-users of coal and could reduce the demand for coal as a fuel source and cause the volume of our sales and/or the prices we receive to decline. These laws and regulations also have imposed, and will continue to impose, costs directly on us.
GHG emissions have increasingly become the subject of international, national, state, provincial and local attention. Coal-fired power plants can generate large amounts of GHG emissions. Accordingly, legislation or regulation intended to limit GHGs will likely indirectly affect our coal operations by limiting our customers’ demand for our products or reducing the prices we can obtain, and also may directly affect our own power operations. In the United States, the EPA, acting under existing provisions of the federal Clean Air Act has promulgated GHG-related reporting and permitting rules. Portions of the EPA’s GHG permitting rules, which were the subject of litigation by some industry groups and states, were struck down in part by the U.S. Supreme Court, but the EPA’s authority to impose GHG control technologies on a majority of large emissions sources, including coal-fired electric utilities, remain in place. In furtherance of President Obama’s announced a Climate Action Plan announced in June 2013, EPA issued in August 2015 final standards for GHG emissions from existing fossil-fuel fired power plants, as well as new, modified and reconstructed fossil-fuel fired power plants. The Clean Power Plan sets standards for existing sources as stringent state-specific carbon emission rates to be phased in between 2020 and 2030. The proposed rule would give states the discretion to use a variety of approaches - including cap-and-trade programs - to meet the standard. In February of 2016, however, the Supreme Court issued an order staying the Clean Power Plan pending judicial review of the rule by the U.S. Court of Appeals for the D.C. Circuit as potentially review by the Supreme Court. The D.C. Circuit issued an expedited briefing schedule for challenges to the rule, and oral argument is schedule for June of 2016. The U.S. Congress has considered, and in the future may again consider, legislation governing GHG emission, including “cap and trade” legislation that would establish a cap on emissions of GHGs covering much of the economy in the United States and would require most sources of GHG emissions to obtain GHG emission “allowances” corresponding to their annual emissions of GHGs. In addition, coal-fired power plants, including new coal-fired power plants or capacity expansions of existing plants, have become subject to opposition by environmental groups seeking to curb the environmental effects of GHG emissions. It is difficult to predict at this time the effect these proposed rules would have on our revenues and profitability. For additional information, see “Business - Material Effects of Regulation” in this report.
In Canada, in September 2012 the federal government released final regulations for reducing GHG emissions from coal-fired electricity generation through the Canadian CO2 Regulations. The Canadian CO2 Regulations required certain Canadian coal-fired electricity generating units, effective July 1, 2015, to achieve an average annual emissions intensity performance standard of 463 tons of CO2 per gigawatt hour. The performance standard applies to new units commissioned after July 1, 2015 and to units that are considered to have reached the end of their useful life at 50 years from the unit’s commissioning date. All of the customer generating assets currently served by the Prairie Operations have annual average CO2 emissions intensity greater than the performance standard other than one of the units at SaskPower’s Boundary Dam Generating Station, which incorporates carbon capture and sequestration technology. New and end-of-life units that incorporate technology for carbon capture and sequestration may apply for a temporary exemption from the performance standard that would remain in effect until 2025, provided that certain implementation milestones are met. Provincial equivalency agreements, under which the Canadian CO2 Regulations would stand down, are being negotiated or discussed with the provinces of Alberta and Saskatchewan. The Prairie coal production in the long-term could be reduced unless certain existing units or new units of the customers served by the Prairie operations are equipped with carbon capture and storage or other technology that achieves the prescribed performance standard, the impact of the Canadian CO2 Regulations is altered by equivalency agreements, or the Canadian CO2 Regulations are changed to lower the performance standard. The impact of the Canadian CO2 Regulations on existing units will vary by location and province.
In addition, various Canadian provincial governments and other regional initiatives are moving ahead with GHG reduction and other initiatives designed to address climate change. For example, under the Climate Change and Emissions Management Act, the Province of Alberta enacted the “Specified Gas Emitters Regulation.” As of January 1, 2008, this enactment requires certain existing facilities with direct emissions of 100,000 metric tons or more of certain specified gases to ensure that the net emissions intensity for a year for an established facility must not exceed 88% of the baseline emissions intensity for the facility. For the 2013 and 2014 compliance periods, Coal Valley Mine exceeded 88% of its baseline emissions and was required to contribute to the Climate Change and Emissions Management Fund by purchasing fund credits. For the 2015 compliance period, the preliminary calculations indicate Coal Valley Mine will not be required to purchase fund credits and could earn fund credits for future use by coming in under 88% of its baseline emissions. It is also anticipated that emissions intensity at Coal Valley Mine will be such that fund credits for future use will be earned, and fund credits will not be required to be purchased. The Government of Alberta has also introduced a complementary Specified Gas Reporting Regulation, which
came into force on October 20, 2004. This legislation requires all industrial emitters emitting 50,000 tons or more of CO2 to report their annual GHG emissions in accordance with the specified Gas Reporting Standard published by the Government of Alberta. In Saskatchewan, Bill 126, The Management and Reduction of Greenhouse Gases Act, was passed in 2010 but is not yet proclaimed in force. The legislation provides a framework for the control of GHG emissions by regulated emitters and will be proclaimed once accompanying draft regulations are finalized. In Alberta, the Government commissioned the Alberta Climate Leadership Panel to make policy recommendations for Alberta to enact to combat climate change. On November 20th, 2015, the Alberta Climate Leadership Panel published a report entailing policy recommendations including the shutdown of coal-fired power generation by the year 2030 and changes to the SGE Regulation that would see costs of emissions to large emitters increase as early as 2017. The Government of Alberta has not yet presented legislation related to combatting climate change, but the Premier in a press conference has indicated that they will be implementing the shutdown and SGE Regulation changes proposed by the Alberta Climate Leadership Panel. The full effects of any new legislation is unknown until draft legislation is presented by the Alberta Government.
As it is unclear at this time what shape additional regulation in Canada will ultimately take, it is not yet possible to estimate the extent to which such regulations will impact our Canadian Operations. However, those operations involve large facilities, so the setting of emissions targets (whether in the manner described above or otherwise) may well affect them and may have a material adverse effect on our business, results of operations and financial performance. These developments in both Canada and the United States could have a variety of adverse effects on demand for the coal we produce. For example, laws or regulations regarding GHGs could result in fuel switching from coal to other fuel sources by electricity generators, or require us, or our customers, to employ expensive technology to capture and sequester carbon dioxide. Political and environmental opposition to capital expenditure for coal-fired facilities could affect the regulatory approval required for the retrofitting of existing power plants. For example, the Naughton power facility, which is located adjacent to the Kemmerer Mine, announced in April 2012 that it is seeking regulatory approval to switch Unit 3 to natural gas from coal. The conversion of Naughton Unit 3 to natural gas would result in significant reduction in coal sales from our Kemmerer Mine, and could have a material adverse effect on our results of operations. However, Rocky Mountain Power, the owner of the Naughton facility, recently announced that the conversion will not take place until at least 2018.
Political opposition to the development of new coal-fired power plants, or regulatory uncertainty regarding future emissions controls, may result in fewer such plants being built, which would limit our ability to grow in the future.
In addition to directly emitting GHGs, our Canadian Operations require large quantities of power. Future taxes on or regulation of power producers or the production of coal, oil and gas or other products may also add to our operating costs. The policy recommendations put forward by the Alberta Climate Leadership Panel, if enacted, have the potential to increase costs of energy products used in the mine operations located in Alberta, such as diesel fuel, gasoline, oil, and electricity.
And many of the developments in the U.S. discussed above that may affect our customers and demand for our coal could also affect us directly through adverse impacts on ROVA.
An inability to obtain and/or renew permits necessary for WMLP’s operations could prevent it from mining certain of its coal reserves.
The slowing pace at which permits are issued or renewed for new and existing mines in WMLP’s area of operations has materially impacted production in Appalachia. Section 402 National Pollutant Discharge Elimination System permits and Section 404 CWA permits are required to discharge wastewater and dredged or fill material into waters of the United States. WMLP’s surface coal mining operations typically require such permits to authorize activities such as the creation of sediment ponds and the reconstruction of streams and wetlands impacted by its mining operations. Although the CWA gives the EPA a limited oversight role in the Section 404 permitting program, the EPA has recently asserted its authorities more forcefully to question, delay, and prevent issuance of some Section 404 permits for surface coal mining in Appalachia. Currently, significant uncertainty exists regarding the obtaining of permits under the CWA for coal mining operations in Appalachia due to various initiatives launched by the EPA regarding these permits, including the issuance in May 2015 of a final rule revising the definition of regulated waters. The slowing pace at which permits are issued or renewed for new and existing mines has materially impacted production in Appalachia, but could also affect other regions in which WMLP operates. An inability to obtain the necessary permits to conduct WMLP’s mining operations or an inability to comply with the requirements of applicable permits could reduce WMLP’s production and cash flows, which could adversely affect its business, financial condition and/or results of operations and our cash flow.
Extensive environmental laws, including existing and potential future legislation, treaties and regulatory requirements relating to air emissions other than GHGs, affect our customers and could reduce the demand for coal as a fuel source and cause coal prices and sales of our coal to materially decline, and could impose additional costs on ROVA.
Our customers, as well as ROVA, are subject to extensive environmental regulations particularly with respect to air emissions other than GHG. Coal contains impurities, including but not limited to sulfur, mercury, chlorine and other elements or compounds, many of which are released into the air when coal is burned. The emission of these and other substances is extensively regulated at the federal, state, provincial and local level, and these regulations significantly affect our customers’ ability to use the coal we produce and, therefore, the demand for that coal. For example, the purchaser of coal produced from the Jewett Mine blends our lignite with compliance coal from Wyoming. Tightened nitrogen oxide and new mercury emission standards could result in the customer purchasing an increased blend of the Wyoming coal in order to reduce emissions. Further, increased market prices for sulfur dioxide emissions allowances and increased coal ash management costs could also favor an increased blend of the lower ash Wyoming compliance coal. In such a case, the customer has the option to increase its purchases of other coal and reduce purchases of our coal or terminate our contract. A termination of the contract or a significant reduction in the amount of our coal that is purchased by the customer could have a material adverse effect on our results of operations and financial condition. The EPA intends to issue or has issued a number of significant regulations that will impose more stringent requirements relating to air, water and waste controls on electric generating units. These rules include the EPA’s final rule for CCR management, announced in December 2014, that further regulates the handling of wastes from the combustion of coal. In addition, in February 2012, the EPA signed a rule to reduce emissions of mercury and toxic air pollutants from new and existing coal- and oil-fired electric utility steam generating units, often referred to as the MATS Rule. In June of 2015, the U.S. Supreme Court reversed the U.S. Court of Appeals for the D.C. Circuit’s decision upholding the rule and held that EPA had failed to properly consider costs when assessing whether to regulate fossil fuel-fired EGUs under the hazardous air pollutant provisions of the Clean Air Act. In June of 2015, the U.S. Supreme Court reversed the U.S. Court of Appeals for the D.C. Circuit and held that EPA had failed to properly consider costs when assessing whether to regulate fossil fuel-fired EGUs under the hazardous air pollutant provisions of the Clean Air Act, referring to the agency’s own estimate that the rule would cost power plants nearly $10 billion a year. The D.C. Circuit remanded the rule to EPA to conduct a cost assessment but without vacatur, allowing the rule to remain in effect while EPA conducts the rulemaking. On December 1, 2015, EPA published a proposed supplemental finding that regulation of EGUs is still “appropriate and necessary” in light of the costs to regulate hazardous air pollutant emissions from the source category. EPA indicated that it expects to issue a final finding by April 15, 2016.
In April 2014, the U.S. Supreme Court upheld the EPA’s Cross-State Air Pollution Rule (“CSAPR”), which would require stringent reductions in emissions of nitrogen oxides and sulfur dioxide from power plants in much of the Eastern United States, including Texas and North Carolina, and in October 2014 the D. C. Circuit granted the EPA’s motion to lift the D.C. Circuit’s stay of the CSAPR, and remanded the case to the D.C. Circuit for further proceedings. In November, 2014 the EPA issued a ministerial rule aligning the CSAPR implementation dates with the Court’s order, with phase 1 reductions beginning in January 2015, and more stringent phase 2 reductions in January 2017. In July 2015, the D.C. Circuit remanded to EPA portions of the 2014 sulfur dioxide and ozone budgets on grounds the reductions were greater than necessary to reduce impacts on downwind states, but did not vacate any portion of the rule. The EPA has indicated that it will address these issues in future rulemakings, but that phase 1 reductions will begin in January 2015, with more stringent phase 2 reductions in January 2017as necessary.The In May 2014, the EPA Administrator signed a final rule that establishes requirements for cooling water intake structures for the withdrawal of cooling water by electric generating plants; the rule is anticipated to affect over 500 power plants.
Considerable uncertainty is associated with air emissions initiatives. New regulations are in the process of being developed, and many existing and potential regulatory initiatives are subject to review by federal or state agencies or the courts. Stringent air emissions limitations are either in place or are likely to be imposed in the short to medium term, and these limitations will likely require significant emissions control expenditures for many coal-fired power plants. For example, the owners of Units 3 and 4, adjacent to our Colstrip mine, are getting considerable pressure from environmental groups to install Selective Catalytic Reduction (“SCR”) technology. Should the owners be forced by the EPA to install such technology, the capital requirements could make the continued operation of the two units unsustainable. As a result, Colstrip and other similarly-situated power plants may switch to other fuels that generate fewer of these emissions or may install more effective pollution control equipment that reduces the need for low-sulfur coal. Any switching of fuel sources away from coal, closure of existing coal-fired power plants, or reduced construction of new coal-fired power plants could have a material adverse effect on demand for, and prices received for, our coal. Alternatively, less stringent air emissions limitations, particularly related to sulfur, to the extent enacted, could make low-sulfur coal less attractive, which could also have a material adverse effect on the demand for, and prices received for, our coal.
The regulation of air emissions in Canada may also reduce the demand for the products of the operations we acquired in the Canadian Acquisition. Specifically, the Alberta Environmental Protection and Enhancement Act (“EPEA”) and its
Canadian Environmental Protection Act, 1999 (“CEPA, 1999”) and the provision for the reporting of pollutants via the National Pollutant Release Inventory (“NPRI”), could also have a significant effect on the customers of our Canadian mines, which in turn could, over time, significantly reduce the demand for the coal produced from those mines.
The customers of our Canadian mines must comply with a variety of environmental laws that regulate and restrict air emissions, including the EPEA and its regulations, and the CEPA, 1999. Because many of these customers’ activities generate air emissions from various sources, compliance with these laws requires our customers in Canada to make investments in pollution control equipment and to report to the relevant government authorities if any emissions limits are exceeded or are made in contravention of the applicable regulatory requirements.
These laws restrict the amount of pollutants that our Canadian customer’s facilities can emit or discharge into the environment. The NPRI, for example, is created under authority of the CEPA, 1999 and is a Canada-wide, legislated, and publicly accessible inventory of specific substances that are released into the air, water, and land. The purpose of the NPRI was to provide comprehensive national data on releases of specified substances, and assists with, identifying priorities for action, encouraging voluntary action to reduce releases, tracking the progress of reductions in releases, improving public awareness and understanding of substances released into the environment, and supporting targeted initiatives for regulating the release of substances.
Regulatory authorities can enforce these and other environmental laws through administrative orders to control, prevent or stop a certain activity; administrative penalties for violating certain environmental laws; and judicial proceedings. If environmental regulatory burdens continue to increase for our Canadian customers, as a result of policy changes or increased regulatory reform relating to the substances reported, it could potentially affect customer operations and future demand for coal.
Risk Factors Relating to our Equity
Provisions of our certificate of incorporation, bylaws, and Delaware law may have anti-takeover effects that could prevent a change of control of our company that stockholders may consider favorable, and the market price of our common stock may be lower as a result.
Provisions in our certificate of incorporation, bylaws and Delaware law could make it more difficult for a third party to acquire us, even if doing so might be beneficial to our stockholders. Provisions of our bylaws impose various procedural and other requirements that could make it more difficult for stockholders to bring about some types of corporate actions such as electing individuals to the board of directors. Our ability to issue preferred stock in the future may influence the willingness of an investor to seek to acquire our company. These provisions could limit the price that some investors might be willing to pay in the future for shares of our common stock and may have the effect of delaying or preventing a change in control. Provisions in the indenture governing the 8.75% Notes regarding certain change of control events could have a similar effect.
Risks Related to Our Acquisitions
The assets we acquired in the San Juan Acquisition may underperform relative to our expectations; the San Juan Acquisition may cause our financial results to differ from our expectations or the expectations of the investment community; and we may not be able to achieve anticipated cost savings or other anticipated objectives.
The success of the San Juan Acquisition will depend, in part, on our ability to integrate the San Juan Entities with our existing business. The integration process may be complex, costly and time consuming. The potential difficulties of integrating the San Juan Entities and realizing our expectations for the San Juan Acquisition include, among other things:
•
failure to implement our strategy for the development of the acquired assets;
•
unanticipated changes in commodity prices;
•
unanticipated changes in applicable laws and regulations;
•
retaining and obtaining required regulatory approvals, licenses and permits;
•
operating risks inherent in our business; and
•
other unanticipated issues, expenses and liabilities.
Many of these factors will be outside of our control, and any one of them could result in increased costs, decreases in the amount of expected revenues and diversion of management’s time and energy, which could materially impact our business,
financial condition and results of operations. In addition, even if our operations and the acquired assets are integrated successfully, we may not realize the full benefits of the San Juan Acquisition, including the synergies or cost savings that we expect. These benefits may not be achieved within the anticipated time frame, or at all. As a result, we cannot assure you that the San Juan Acquisition will result in the realization of the full benefits anticipated.
SJGS, San Juan’s primary customer, is required to shut down half of its power producing units at the end of 2017, which we expect will result in a significant decrease in SJGS’s demand for coal produced by the San Juan mine.
On October 1, 2014 SJGS reached an agreement with the New Mexico agencies, non-governmental organizations, and the EPA to shut down two of its power generating units by December 31, 2017 to comply with requirements under the Clean Air Act. Under the same agreement, SJGS also agreed to install selective non-catalytic reduction (“SNCR”) emission control technology on its two units that will remain active, with the deadline for that installation at the end of 2016. Following the shutdown of the units, four of SJGS’s nine owning utilities will cease ownership, with PSNM and Tucson Electric expected to remain as the primary customers of the station. In August 2015, the parties agreed to modifications to the original agreement. The modifications did not alter provisions requiring installation of SNCR or shut down of two of the units, but it did include a commitment by PSNM to make a filing before the New Mexico PRC demonstrating the ongoing economic viability of SJGS beyond 2022. This agreement has not yet been approved by the New Mexico PRC. As a result of these developments, we expect that SJGS’s demand for coal produced by the San Juan mine will decrease significantly, which will negatively impact our results of operations and financial condition unless we are able to find a suitable alternative customer for the coal produced by the San Juan mine. Because the San Juan mine is a mine-mouth facility, we may have difficulty identifying customers.
SJCC is subject to pending litigation that could result in the temporary interruption of its mining operations.
SJCC is subject to certain litigation related to its operations, including an Action filed by WildEarth Guardians (“WEG”) on February 27, 2013, in the United States District Court for the District of Colorado seeking review of the Office of Surface Mining (“OSM”) decisions and decisions of the Assistant Secretary of the Interior approving mine plans or mine plan amendments concerning seven separate coal mines in Colorado, Montana, New Mexico, and Wyoming. Among the decisions being challenged is the January 2008 approval of the mining plan modification for the San Juan Mine. WEG alleges that in approving the plans or plan amendments, OSM engaged in a “pattern and practice of failing to comply with” the requirements of the National Environmental Policy Act by failing “to ensure that the public was appropriately involved in the adoption of” the mine plans and by failing to “take a hard look at a number of potentially significant environmental impacts.” On February 7, 2014, the case was transferred to the U.S. District Court for the District of New Mexico. On March 14, 2014, WEG filed an amended petition. Settlement discussions among the parties are ongoing and no trial date has been scheduled. In the event the parties reach a settlement or litigation proceeds and WEG prevails in the case, there is the potential that San Juan would be required to cease mining activities, pending OSM’s completion of a supplemental environmental impact analysis that supports the Assistant Secretary of the Interior’s approval of the mining plan modification for the San Juan Mine in compliance with the National Environmental Policy Act. Any such interruption of mining activities at San Juan could have an adverse impact on our results of operations and financial condition.
We may not have uncovered all risks associated with our recent acquisition activity, and significant liabilities related to such activity of which we are not aware may exist now or arise in the future.
In connection with the San Juan, Canadian and Buckingham Acquisitions, and our acquisition of a controlling interest in WMLP, we assumed the risk of unknown, and certain known, liabilities. We may become responsible for unexpected liabilities that we failed or were unable to discover in the course of performing due diligence in connection with these acquisitions or for costs associated with known liabilities that exceed our estimates. Under the various purchase arrangements relating to these acquisitions, there may not be recourse to indemnification should we discover a previously unknown liability, whether material or immaterial.
We may not realize the anticipated benefits of recent or future acquisitions, potential synergies, due to challenges associated with integration and other factors.
The long-term success of the acquisitions will depend in part on the success of our management in efficiently integrating the operations, technologies and personnel acquired entities or operations. Our management’s inability to meet the challenges involved in successfully integrating acquired entities or operations or to otherwise realizing the anticipated benefits of such transactions could harm our results of operations.
The challenges involved in integration include:
•
integrating the operations, processes, people and technologies;
•
coordinating and integrating regulatory, benefits, operations and development functions;
•
demonstrating to customers acquisition will not result in adverse changes in coal quality, delivery schedules and other relevant deliverables;
•
managing and overcoming the unique characteristics of acquired entities or operations, such as the specific mining conditions at each of the acquired mines; retaining the personnel of acquired entities or operations and integrating the business cultures, operations, systems and clients of acquired entities or operations with our own;
•
consolidating corporate and administrative infrastructures and eliminating duplicative operations and
•
administrative functions; and
•
identifying the potential unknown liabilities associated with the Acquisitions.
In addition, overall integration will require substantial attention from our management, particularly in light of the geographically dispersed operations of acquired mines relative to our other mines and operations and the unique characteristics of the acquired assets. If our senior management team is required to devote considerable amounts of time to the integration process, it will decrease the time they will have to manage our business, develop new strategies and grow our business. If our senior management is not able to manage the integration process effectively, or if any significant business activities are interrupted as a result of the integration process, our business could suffer.
Furthermore, the anticipated benefits and synergies of acquisitions are based on assumptions and current expectations, with limited actual experience, and assume that we will successfully integrate and reallocate resources without unanticipated costs and that our efforts will not have unforeseen or unintended consequences. In addition, our ability to realize the benefits and synergies of the acquisitions could be adversely impacted to the extent that relationships with existing or potential customers, suppliers or the workforce is adversely affected as a consequence of the Acquisitions, as a result of further weakening of global economic conditions, or by practical or legal constraints on our ability to successfully integrate operations.
We cannot assure you that we will successfully or cost-effectively integrate acquired entities or operations into our operations in a timely manner, or at all, and we may not realize the anticipated benefits of the acquisition, including potential synergies or growth opportunities, to the extent or in the time frame anticipated. The failure to do so could have a material adverse effect on our financial condition, results of operations and business.
Our operations outside the United States may subject us to additional risks.
A significant portion of our assets, operations and revenues are located in Canada, and we will be subject to risks inherent in business operations outside of the United States. These risks include, without limitation:
•
impact of currency exchange rate fluctuations among the U.S. dollar, the Canadian dollar and foreign currencies relating to our export business, which may reduce the U.S. dollar value of the revenues, profits and cash flows we receive from non-U.S. markets or of our assets in non-U.S. countries or increase our supply costs, as measured in U.S. dollars in those markets;
•
exchange controls and other limits on our ability to repatriate earnings from other countries;
•
political or economic instability, social or labor unrest or changing macroeconomic conditions or other changes in political, economic or social conditions in the respective jurisdictions;
•
different regulatory structures (including creditor rights that may be different than in the United States) and unexpected changes in regulatory environments, including changes resulting in potentially adverse tax consequences or imposition of onerous trade restrictions, price controls, industry controls, safety controls, employee welfare schemes or other government controls;
•
increased financial accounting and reporting burdens and complexities resulting from the conversion and integration of the Canadian Subsidiaries’ Canadian dollar denominated, non-GAAP results of operations and statement of financial condition into GAAP-complaint financial statements that can be consolidated with our historical financial reports;
•
tax rates that may exceed those in the United States and earnings that may be subject to withholding requirements or that may be subject to tax in the United States prior to repatriation and incremental taxes upon repatriation;
•
difficulties and costs associated with complying with, and enforcement of remedies under, a wide variety of complex domestic and international laws, treaties and regulations;
•
distribution costs, disruptions in shipping or reduced availability of freight transportation; and
•
imposition of tariffs, quotas, trade barriers and other trade protection measures, in addition to import or export licensing requirements imposed by various foreign countries.
In addition, our management may be required to devote significant time and resources to adapting our systems, policies and procedures in order to successfully manage the integration and operation of foreign assets.
The Buckingham and San Juan Acquisitions may subject us to increased regulation and risks associated with underground mining.
The operations we acquired in the Buckingham Acquisition and the San Juan Acquisition primarily consist of underground mines. Underground mining operations are generally subject to more stringent safety and health standards than surface mining operations. More stringent state and federal mine safety laws and regulations have included increased sanctions for non-compliance. Future workplace accidents are likely to result in more stringent enforcement and possibly the passage of new laws and regulations. Our re-entry into underground mining operations will subject us to increased regulatory scrutiny and increased costs of regulatory compliance.
ITEM 1B
ITEM 1B
- UNRESOLVED STAFF COMMENTS.
None
ITEM 2
ITEM 2
- PROPERTIES.
See “Coal - U.S. Segment - Properties,” “Coal - Canada Segment - Properties,” “Coal - WMLP Segment - Properties,” and “Power Segment” under Item 1 for information relating to our properties and reserves.
ITEM 3
ITEM 3
- LEGAL PROCEEDINGS.
We are subject, from time-to-time, to various proceedings, lawsuits, disputes, and claims (“Actions”) arising in the ordinary course of our business. Many of these Actions raise complex factual and legal issues and are subject to uncertainties. We cannot predict with assurance the outcome of Actions brought against us. Accordingly, adverse developments, settlements, or resolutions may occur and may result in a negative impact on income in the quarter of such development, settlement, or resolution. However, we do not believe that the outcome of any current Action would have a material adverse effect on our financial results.
ITEM 4
ITEM 4
- MINE SAFETY DISCLOSURE.
On July 21, 2010, Congress enacted the Dodd-Frank Wall Street Reform and Consumer Protection Act (the "Dodd-Frank Act"). Section 1503(a) of the Dodd-Frank Act contains reporting requirements regarding mine safety. Mine safety violations or other regulatory matters, as required by Section 1503(a) of the Dodd-Frank Act and Item 104 of Regulation S-K, are included as Exhibit 95.1 to this report on Form 10-K.
PART II
ITEM 5
ITEM 5
- MARKET FOR REGISTRANT’S COMMON EQUITY, RELATED STOCKHOLDER MATTERS AND ISSUER PURCHASES OF EQUITY SECURITIES.
Market Information
Our common stock is listed and traded on the NASDAQ Global Market under the symbol WLB.
Holders
As of March 9, 2016, there were 1,066 holders of record of our common stock.
The following table shows the range of sales prices for our common stock for the past two years, as reported by the NASDAQ Global Market.
Dividend Policy
Holders of our common stock are entitled to receive such dividends as our Board may declare from time to time from any surplus that we may have. We have not paid dividends on our common stock for some time and we do not anticipate paying any common stock dividends in the near future. In addition, the 8.75% Notes, the WCC Term Loan Facility and the WCC Revolving Credit Facility agreement restrict our ability to pay dividends on, or make other distributions in respect of, our capital stock unless we are able to meet certain ratio tests or other financial requirements. Should we be permitted to pay dividends pursuant to such instruments, the payment of such dividends will be dependent upon earnings, financial condition and other factors considered relevant by our Board and will be subject to limitations imposed under Delaware law.
Securities Authorized for Issuance Under Equity Compensation Plans
The information relating to our equity compensation plans required by Item 5 is incorporated by reference to such information set forth in Item 12 - Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters contained herein.
Issuer Purchase of Equity Securities
None.
Stock Performance Graph
The following performance graph compares the cumulative total stockholder return on our common stock for the five-year period December 31, 2010 through December 31, 2015 with (i) the cumulative total return over the same period of the NASDAQ Index, (ii) the cumulative total return over the same period of the NYSE MKT Composite Index, (iii) our former peer group, which consisted of Arch Coal, Alliance Resource Partners LP, Cloud Peak Energy, Foresight Energy LP, Peabody Energy, and Rhino Resource Partners LP and (iv) our current peer group index, which consists of Alliance Resource Partners LP, Arch Coal, Cloud Peak Energy, CONSOL Energy, and Peabody Energy. The graph assumes that:
•
You invested $100 in Westmoreland Coal common stock and in each index at the closing price on December 31, 2010;
•
All dividends were reinvested;
•
Annual reweighting of the peer groups; and
•
You continued to hold your investment through December 31, 2015.
You are cautioned against drawing any conclusions from the data contained in this graph, as past results are not necessarily indicative of future performance. The indices used are included for comparative purposes only and do not indicate an opinion of management that such indices are necessarily an appropriate measure of the relative performance of our common stock.
1.
Includes reinvestment of dividends
2.
2015 Peer Group: Alliance Resource Partners LP, Arch Coal, Cloud Peak Energy, CONSOL Energy, and Peabody Energy
3.
2014 Peer Group: Arch Coal, Alliance Resource Partners LP, Cloud Peak Energy, Foresight Energy LP, Peabody Energy, and Rhino Resource Partners LP
ITEM 6
ITEM 6
- SELECTED FINANCIAL DATA.
Westmoreland Coal Company and Subsidiaries
Five-Year Review
____________________
(1)
Includes asset impairment charges of $136.2 million in 2015, comprised of an impairment of $133.1 million at ROVA and $3.1 million at our Coal Valley mine. Includes a loss on extinguishment of debt of $5.4 million, $49.2 million, $0.1 million, $2.0 million and $17.0 million in 2015, 2014, 2013, 2012 and 2011, respectively. Includes a derivative loss of $5.6 million and $31.1 million in 2015 and 2014, respectively. Includes restructuring charges of $0.7 million, $15.0 million and $5.1 million in 2015, 2014 and 2013, respectively.
(2)
On April 28, 2014, we acquired the Canadian Subsidiaries, and on December 31, 2014, we acquired Westmoreland Resources GP, LLC. Our results of operations, balance sheets, and other consolidated data include the acquired entities subsequent to their respective dates of acquisition.
(3)
On January 31, 2012, we acquired the Kemmerer Mine. Our results of operations include Kemmerer’s results of operations from the date of acquisition.
(4)
All amounts presented net of current deferred tax asset due to adoption of ASU 2015-17 on December 31, 2015.
(5)
Adjusted EBITDA, a non-GAAP measure, is defined and reconciled to net loss at the end of this “Selected Financial Data” section.
We did not declare cash dividends on common shares for the five years ended December 31, 2015. The financial data presented above should be read in conjunction with Management’s Discussion and Analysis of Financial Condition and Results of Operation in Part II, Item 7
ITEM 7
- MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS.
The following discussion and analysis contains forward-looking statements and estimates that involve risks and uncertainties. Actual results could differ materially from these estimates. Factors that could cause or contribute to differences from estimates include those discussed under “Cautionary Note Regarding Forward-Looking Statements” and “Risk Factors” contained in Item 1 above.
Overview
Westmoreland Coal Company is an energy company employing approximately 3,248 employees. We conduct our operations through our subsidiaries and our principal sources of cash are distributions from our operating subsidiaries. At December 31, 2015, our operations included 12 wholly-owned coal mines in the U.S. and Canada, a char production facility, a 50% stake in an activated carbon plant, and two coal-fired power generation units. We also own the general partner of, and 93.8% of the total equity interest in WMLP which owns and operates five mining complexes in Ohio and one mine in Wyoming. We sold 53.3 million tons of coal in 2015.
We classify our business into six segments, including four operating segments (Coal - U.S., Coal - Canada, Coal - WMLP, Power) and two non-operating segments (Heritage and Corporate). Our Heritage segment primarily includes the costs of benefits we provide to former mining operation employees and our Corporate segment consists primarily of corporate administrative expenses and intersegment transactions.
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.
We sell almost all of our coal and electricity production under long-term agreements. Our long-term coal contracts typically contain either full pass-through of our costs or price escalation and adjustment provisions, pursuant to which the price for our coal may be periodically revised in line with broad economic indicators such as the consumer price index, commodity-specific indices such as the PPI-light fuel oils index, and/or changes in our actual costs. We refer to these contracts as “cost protected” contracts.
For our contracts that are not cost protected in nature, we have exposure to inflation and price risk for supplies used in the normal course of production such as diesel fuel and explosives. We manage these items through strategic sourcing contracts in normal quantities with our suppliers and may use derivatives from time-to-time.
Recent Developments
Please see Item 1 - Business, under “Overview,” “2015 Transactions” and “Recent Developments” for information regarding the following transactions that occurred during 2015:
•
Buckingham Acquisition
•
Kemmerer Drop
•
Debt Facilities (WCC Revolving Credit Facility Amendment and WMLP Revolving Credit Facility)
Results of Operations
Items that Affect Comparability of Our Results
The table below summarizes income (expense) items that do not relate directly to ongoing operations:
Loss on Extinguishment of Debt: In 2015 we recorded a $5.3 million loss on the extinguishment of debt related to the early extinguishment of a portion of the WCC Term Loan Facility as a result of the Kemmerer drop. This loss is down from 2014, where we recorded $49.2 million in loss on the extinguishment of debt related to our refinancing of our then existing 10.75% Notes, WML term debt, and WMLP debt.
Derivative Loss: Derivative losses are the result of decreasing power prices associated with our power purchase contract for our ROVA facility in the Power Segment.
Acquisition and Transition costs: 2015 acquisition and transition costs of $6.0 million include costs incurred in connection with the drop of Kemmerer to WMLP as well as our acquisition of the San Juan mine, which closed in 2016. In 2014 we recorded acquisition and transaction costs of $26.8 million primarily as a result of our WMLP and Canadian Acquisitions, including the impact on cost of sales related to the sale of inventory written up to fair value in the acquisition.
Restructuring Charges: Our restructuring charges relate primarily to our 2013 ROVA Restructuring plan as well as Acquisition related restructuring plans for our WMLP and Canadian Acquisitions. Refer to Note 7 in Item 8, Financial Statements and Supplementary Data for more information on these plans.
Gain (loss) on Foreign Exchange: In 2015 we recorded a gain on foreign exchange based on currency fluctuations. In 2014, we recorded a $4.0 million loss on foreign exchange. The majority of this loss in 2014 relates to two foreign currency exchange forward contracts to purchase Canadian dollars in order to hedge a portion of our exposure to fluctuating rates of exchange on Canadian dollar-denominated Canadian Acquisition cash flows. No foreign exchange hedges remained open during 2015.
Loss on Impairment: In 2015 we recorded impairment charges of $133.1 million and $3.2 million in our Power and Coal-Canada segments, respectively. The impairment in the Power segment was due primarily to the significant decrease in power prices in the region served by our ROVA power plant. We expect the depressed power prices to persist in the future. The impairment in Coal - Canada was due primarily to depressed coal prices in the export market that Coal Valley serves. Refer to Note 3 in Item 8, Financial Statements and Supplementary Data for more information on these charges.
Incremental Interest and Bridge Facility Commitment Fee: We recorded $11.2 million of incremental interest expense related to additional debt issued in connection with the Canadian Acquisition. This incremental interest represents interest expense from the February 7, 2014 closing date of the 10.75% Notes to the April 28, 2014 closing date of the Canadian Acquisition. We also recorded $4.9 million of interest expense related to the Canadian Acquisition bridge facility. Upon closing of the $425 million private offering of 10.75% Notes, our bridge facility commitment expired unexercised and as a result, the related commitment fee of $4.9 million was expensed and is included in Interest expense.
2015 Compared to 2014
Summary
The following table shows the comparative consolidated results and changes between periods:
____________________
(1)
Adjusted EBITDA , a non-GAAP measure, is defined and reconciled to net loss in Item 6, Selected Financial Data.
Our 2015 revenues increased primarily due to the Canadian, WMLP and Buckingham acquisitions. Our net loss applicable to common shareholders for 2015 increased by $30.2 million, with $8.0 million arising from an increase in the Items that Affect Comparability of our Results explained above and the remaining increase arising from operating losses in our Coal - WMLP segment as a result of challenging market and mining conditions.
Coal - U.S. Segment Operating Results
The following table summarizes key metrics for the Coal - U.S. Segment. As a result of the Kemmerer Drop, results for all periods presented reflect Kemmerer as part of the Coal - WMLP segment and not part of the Coal - US segment:
____________________
(1)
Adjusted EBITDA, a non-GAAP measure, is defined and reconciled to net loss in Item 6, Selected Financial Data.
Our 2015 U.S. coal segment revenues increased primarily due to the Buckingham Acquisition which was completed on January 1, 2015. For the year ended December 31, 2015, revenues for Buckingham were $80.5 million and operating losses were $3.2 million. Operating income improved as a result of 2014 acquisition costs related to the Sherritt acquisition not recurring in 2015. Both operating income and Adjusted EBITDA increased due to strong 2015 first-half revenue and cost control at our WRI mine. However, growth in revenue, operating income, and Adjusted EBITDA was pressured in 2015 as a result of mild weather and unexpected customer outages.
Coal - Canada Segment Operating Results
____________________
(1)
Adjusted EBITDA, a non-GAAP measure, is defined and reconciled to net loss in Item 6, Selected Financial Data.
* Not meaningful
The Canadian Acquisition was completed on April 28, 2014; therefore, there are only eight months of activity for the year ended December 31, 2014. Operating income in 2014 was negatively impacted by $14.2 million of cost of sales related to the sale of inventory written up to fair value in the Canadian acquisition and $9.6 million of restructuring charges. Results of operations were also challenged by continued declines in export prices.
Coal - WMLP Segment Operating Results
The following table summarizes key metrics for the Coal - WMLP Segment. As a result of the Kemmerer Drop, results for all periods presented reflect Kemmerer as part of the Coal - WMLP segment and not part of the Coal - US segment:
____________________
(1)
Adjusted EBITDA, a non-GAAP measure, is defined and reconciled to net loss in Item 6, Selected Financial Data.
Revenues increases as a result of the WMLP acquisition on December 31, 2014. Operating income decreased in 2015 primarily due to challenging market conditions at the Ohio locations and difficult mining conditions at Kemmerer.
Power Segment Operating Results
____________________
(1)
Adjusted EBITDA, a non-GAAP measure, is defined and reconciled to net loss in Item 6, Selected Financial Data.
While revenue remained consistent year-over-year, operating loss increased in 2015 due to an impairment charge on our long-lived assets of $133.1 million during the fourth quarter. Operating loss also included a $5.6 million loss on our power derivative in 2015, down from $31.1 million in losses on the derivative in 2014. Decreasing power prices and unseasonably mild weather throughout 2015 also contributed to declines in results compared to 2014.
Heritage Segment Operating Results
Our 2015 heritage segment operating expenses were comparable to 2014.
Corporate Segment Operating Results
The following table shows comparative corporate segment’s operating expenses and percentage change between periods:
Our 2015 corporate segment operating expenses increased primarily as a result of increased insurance claims filed with our captive insurance company, as well as increases in stock compensation expense and other professional services.
Nonoperating Results
Our interest expense for 2015 increased by $13.0 million compared to 2014 primarily due to higher debt levels. In 2015 we also incurred a $5.4 million loss on early extinguishment of debt due to the early repayment of approximately $94.1 million of our WCC Term Loan Facility loan in connection with the receipt of proceeds from the Kemmerer Drop, down from $49.2 million in early extinguishment of debt losses in 2014 as described above. Our income tax benefit increased by $20.0 million in 2015 due to the release of certain deferred tax asset valuation allowances in Canada, discussed further in Note 17 of Item 8, Financial Statements and Supplementary Data.
2014 Compared to 2013
Summary
____________________
(1)
Adjusted EBITDA , a non-GAAP measure, is defined and reconciled to net loss in Item 6, Selected Financial Data.
* Not meaningful
Our revenues for 2014 increased primarily due to the Canadian Acquisition. Our net loss applicable to common shareholders for 2014 increased by $167.0 million, with $137.0 million arising from an increase in the Items that Affect Comparability of our Results explained above. The primary factors, in aggregate, driving the remaining increase in net loss were:
Coal - U.S. Segment Operating Results
The following table summarizes key metrics for the Coal - WMLP Segment. As a result of the Kemmerer Drop, results for all periods presented reflect Kemmerer as part of the Coal - WMLP segment and not part of the Coal - US segment:
____________________
(1)
Adjusted EBITDA, a non-GAAP measure, is defined and reconciled to net loss in Item 6, Selected Financial Data.
Our 2014 U.S. coal segment revenues and tons sold increased primarily due to new customer sales at our Absaloka mine and fewer customer outages affecting our Absaloka and Beulah mines. Operating income was negatively impacted by weather impacts, rail service issues at our Absaloka mine, acquisition costs, and increased maintenance expenses. These decreases in operating income were partially offset with increased revenues described above.
Coal - WMLP Segment Operating Results
The following table summarizes key metrics for the Coal - WMLP Segment. As a result of the Kemmerer Drop, results for all periods presented reflect Kemmerer as part of the Coal - WMLP segment and not part of the Coal - US segment:
____________________
(1)
Adjusted EBITDA, a non-GAAP measure, is defined and reconciled to net loss in Item 6, Selected Financial Data.
Both periods presented are comprised of Kemmerer mine operations, with 2014 also including $2.8 million of WMLP expenses related to severance charges that occurred on the December 31, 2014 WMLP acquisition date. The Kemmerer mine was consistent year-over-year, with the decrease in operating income arising from the severance charges described above.
Power Segment Operating Results
____________________
(1)
Adjusted EBITDA, a non-GAAP measure, is defined and reconciled to net loss in Item 6, Selected Financial Data.
Our 2014 power segment revenues decreased and operating income decreased to an operating loss due to the renegotiated ROVA contract, unfavorable power prices and cooler than average weather during the summer. Operating income was also negatively impacted by $31.1 million of derivative losses on ROVA's purchased-power contracts.
Heritage Segment Operating Results
The following table shows comparative heritage segment’s operating expenses and percentage change between periods:
Our 2014 heritage segment operating expenses were comparable to 2013.
Corporate Segment Operating Results
The following table shows comparative corporate segment’s operating expenses and percentage change between periods:
Our 2014 corporate segment operating expenses increased due to higher compensation expenses.
Nonoperating Results (including interest expense, interest income, other income (loss), income tax expense (benefit), and net loss attributable to noncontrolling interest)
Our interest expense for 2014 increased to $84.2 million compared with $39.9 million for 2013 primarily due to higher debt levels. Our interest income for 2014 increased to $6.4 million compared with $1.4 million for 2013 due to the Canadian Acquisition. Our net loss attributable to noncontrolling interest for 2014 decreased to $0.9 million compared with $3.4 million for 2013 related to the elimination of the noncontrolling interest effective January 1, 2014 offset with the start of noncontrolling interest effective December 31, 2014 regarding the WMLP Acquisition.
Liquidity and Capital Resources
We had the following liquidity at December 31, 2015 and December 31, 2014:
We anticipate that our cash from operations, cash on hand and available borrowing capacity will be sufficient to meet our investing, financing, and working capital requirements for the foreseeable future.
We conduct our operations through subsidiaries. Our parent company has significant cash requirements to fund our debt obligations, ongoing heritage health benefit costs, pension contributions, and corporate overhead expenses. The principal sources of cash flow to the parent company are distributions from our principal operating subsidiaries. The cash at all of our subsidiaries is immediately available, except WRMI and WMLP. The cash at our captive insurance entity, WRMI, is available to us through dividends and is subject to maintaining a statutory minimum level of capital, which is two hundred and fifty thousand dollars. The cash at WMLP is available to us through quarterly distributions. WMLP resumed quarterly distributions of $0.20 per unit for the first quarter of 2015, paid in April 2015, or $4.6 million annually. Based on our current ownership of WMLP, we would expect to receive approximately 93.8% of WMLP’s distributions. In addition as WMLP's general partner, we are entitled to incentive distribution rights.
Debt Obligations
8.75% Notes
On December 16, 2014, we completed the issuance of $350.0 million in aggregate principal amount of 8.75% Notes. The 8.75% Notes were issued at a 1.292% discount, mature on January 1, 2022, and bear a fixed interest rate of 8.75% payable semiannually, on January 1 and July 1 of each year, commencing July 1, 2015. The 8.75% Notes are our senior secured indebtedness, rank equally in right of payment with all of our existing and future senior indebtedness, including the WCC Term Loan Facility, and rank senior to all of our existing and future indebtedness that is expressly subordinated to the 8.75% Notes.
We may redeem all or part of the 8.75% Notes beginning on January 1, 2018 at the redemption prices set forth in the 8.75% Notes agreement, and prior to January 1, 2018 at 100% of the principal amount plus the applicable premium described in the 8.75% Notes agreement. In addition, at any time prior to January 1, 2018, we may redeem up to 35% of the aggregate principal amount of the 8.75% Notes with the net cash proceeds of certain equity offerings at a redemption price equal to 108.75% of the principal amount of the 8.75% Notes to be redeemed, together with accrued and unpaid interest, if any, to the redemption date, subject to certain conditions.
The 8.75% Notes are guaranteed by Westmoreland Energy LLC, Westmoreland Kemmerer, Inc., Westmoreland Mining LLC, Westmoreland Resources, Inc., Westmoreland Coal Sales Company Inc. and WCC Land Holding Company Inc. and, to the extent applicable, their respective subsidiaries (other than Absaloka Coal, LLC, Westmoreland Risk Management, Inc. and certain other immaterial subsidiaries). The 8.75% Notes are not guaranteed by Westmoreland Canada LLC or any of its subsidiaries, nor are they guaranteed by the GP or WMLP, referred to as the Non-guarantors.
The 8.75% Notes and the guarantees are secured equally and ratably with the WCC Term Loan Facility (i) by first priority liens on substantially all of our and the guarantor parties’ tangible and intangible assets (excluding certain equity interests, mineral rights and sales contracts and certain assets subject to existing liens) and (ii) subject to the WCC Revolving Credit Facility, a second priority lien on substantially all cash, accounts receivable and inventory of the Company and the guarantors, and any other property with respect to, evidencing or relating to such cash, accounts receivable and inventory (whether now owned or hereinafter arising or acquired) and the proceeds and products thereof, subject in each case to permitted liens and certain exclusions (the “Notes Collateral”). The Notes Collateral is shared equally with the lenders under the WCC Term Loan Facility, who hold identical first and second priority liens, as applicable, on the Notes Collateral.
The 8.75% Notes restrict our and our restricted subsidiaries’ ability to, among other things, (i) incur, assume or guarantee additional indebtedness or issue preferred stock; (ii) declare or pay dividends on, or make other distributions in respect of, their capital stock; (iii) purchase or redeem or otherwise acquire for value any capital stock or subordinated indebtedness; (iv) make investments, other than permitted investments; (v) create certain liens or use assets as security; (vi) enter into agreements restricting the ability of any restricted subsidiary to pay dividends, make loans, or any other distributions to us or other restricted subsidiaries; (vii) engage in transactions with affiliates; and (viii) consolidate or merge with or into other companies or transfer all or substantially all of their assets.
The 8.75% Notes contain, among other provisions, events of default and various affirmative and negative covenants. As of December 31, 2015, we were in compliance with all covenants for the 8.75% Notes, and we expect compliance with our covenants to continue.
Restricted Group and Unrestricted Group Results
Under the 8.75% Notes, the WCC Term Loan Facility and the WCC Revolving Credit Facility agreements; the GP, WMLP and all of WMLP’s subsidiaries (including WKFCH) were automatically designated as “unrestricted subsidiaries” (the “Unrestricted Group”) following the closing of the WMLP Transactions. All of our other subsidiaries are restricted subsidiaries (the “Restricted Group). Only the Restricted Group provides credit support for our obligations under the 8.75% Notes, the WCC Term Loan Facility and the WCC Revolving Credit Facility. The Unrestricted Group is not subject to any of the restrictive covenants in the 8.75% Notes, the WCC Term Loan Facility or the WCC Revolving Credit Facility. Conversely, the Restricted Group are not obligors of the $175.0 million WMLP Financing Agreement and such indebtedness is non-recourse to the Restricted Group and its assets.
The 8.75% Notes require summary information for the Restricted Group and Unrestricted Group which is provided as follows:
For the year ended December 31, 2014, the Adjusted EBITDA for the Restricted Group was the same as the Company's consolidated Adjusted EBITDA. There was no Adjusted EBITDA associated with the Unrestricted Group since the WMLP Transactions closed on December 31, 2014. For the year ended December 31, 2015, Adjusted EBITDA associated with the Restricted Group and Unrestricted Group was $150.5 million and $66.1 million, respectively.
Non-guarantor Restricted Subsidiaries Results
The 8.75% Notes require summary information for non-guarantor subsidiaries which is provided as follows:
Absaloka Coal, LLC, Westmoreland Canada LLC, Westmoreland Risk Management, Inc. (“WRMI”), the Canadian Subsidiaries and our Netherlands subsidiary (collectively, the “non-guarantor Restricted Subsidiaries”) had $809.8 million in total assets as of December 31, 2015, representing approximately 53.9% of our consolidated total assets, and generated $430.5 million in revenue for the year ended December 31, 2015 representing approximately 30.5% of our consolidated revenue and generated Adjusted EBITDA of $107.4 million representing approximately 49.6% of our consolidated Adjusted EBITDA. As of December 31, 2015, our non-guarantor Restricted Subsidiaries had $52.8 million of total indebtedness and $466.2 million of total liabilities, and our non-guarantor Canadian Subsidiaries had availability of up to $18.0 million under the Canadian tranche of the WCC Revolving Credit Facility.
WCC Term Loan Facility
Effective as of December 16, 2014, we entered into the WCC Term Loan Facility which provided for an initial $350.0 million term loan. The term loan was issued at a 2.5% discount and matures on December 16, 2020. We may elect to have borrowings under the term loan bear interest at a per annum rate of (i) one, two-, three- or six-month LIBOR plus 6.50% or (ii) a base rate (determined with reference to the highest of the prime rate, the Federal Funds Rate plus 0.05%, and one-month LIBOR plus 1.00%) plus 5.50%. The interest rate at December 31, 2015 was 7.50%. With the addition of the Add-on described below, the quarterly principal payment due commencing March 31, 2015 is $1.1 million. Under the WCC Term Loan Facility, we are required to offer a portion of our Excess Cash Flow (as defined by the Agreement) for each fiscal year, beginning with the fiscal year ended December 31, 2015.
The WCC Term Loan Facility contains customary affirmative covenants, negative covenants, and events of default. Pursuant to the terms and provisions of the related Guaranty and Collateral Agreement, the obligations under the term loan are secured by identical first and second priority liens, as applicable, on the Notes Collateral. As of December 31, 2015, we were was in compliance with all covenants for the term loan, and we expect compliance with our covenants to continue.
The WCC Term Loan Facility is guaranteed by Westmoreland Energy LLC, Westmoreland Kemmerer, Inc., Westmoreland Mining LLC, Westmoreland Resources, Inc., Westmoreland Coal Sales Company, Inc. and WCC Land Holding
Company, Inc. and certain other direct and indirect subsidiaries of the Company (other than Absaloka Coal, LLC, Westmoreland Risk Management, Inc., Westmoreland Canada LLC or any of its subsidiaries and certain other immaterial subsidiaries).
WCC Term Loan Facility Add-on
On January 22, 2015, we amended the WCC Term Loan Facility to increase the borrowings by $75.0 million, for an aggregate principal amount of $425.0 million. The amendments to the WCC Term Loan Facility were made in connection with the acquisition of Buckingham. Net proceeds were $71.0 million after a 2.5% discount, 1.5% broker fee, a consent fee of 1.17%, and $0.1 million of additional debt issuance costs.
WCC Revolving Credit Facility
During the first quarter of 2014, we amended our existing WCC Revolving Credit Facility to increase the maximum available borrowing amount to $60.0 million. On December 16, 2014, we further amended the WCC Revolving Credit Facility Agreement, decreasing the maximum borrowing amount to $50.0 million in the aggregate, consisting of a $30.0 million sub-facility available to our U.S. borrowers and $20.0 million sub-facility available to our Canadian borrowers. The maximum principal amount available for borrowings under the credit agreement can be increased to $75.0 million under certain circumstances. The facility may support an equal amount of letters of credit, which would reduce the balance available under the facility. At December 31, 2015, availability under the WCC Revolving Credit Facility was $28.2 million with an outstanding balance of $19.8 million supporting letters of credit and $2.0 million drawn on the revolver. All extensions of credit under the facility are secured by a first priority security interest in and lien on our cash, inventory and accounts receivable, certain other assets and proceeds thereof. The WCC Revolving Credit Facility has a maturity date of December 31, 2018. We capitalized debt issuance costs of $0.7 million in 2014 related to the WCC Revolving Credit Facility amendments.
Our borrowing base under the WCC Revolving Credit Facility is determined by reference to our eligible inventory and accounts receivable, and is reduced by the outstanding amount of standby and commercial letters of credit. Borrowings under the WCC Revolving Credit Facility initially bear interest either at a rate 0.75% in excess of the base rate or at a rate 2.75% per annum in excess of LIBOR, at our election. An unused line fee of 0.50% per annum is payable monthly on the average unused amount of the revolver.
The loan agreement contains various affirmative, negative and financial covenants. Financial covenants in the agreement require that we meet or exceed certain specified minimum fixed charge coverage ratios, as defined, including a consolidated ratio of 1.15. The Company met these covenant requirements as of December 31, 2015, and we expect compliance with our covenants to continue.
WMLP Term Loan Facility
On December 31, 2014, WMLP entered into its WMLP Term Loan Facility, which consists of a $175.0 million term loan, with an option for an additional $120.0 million in term loans for acquisitions, which was exercised on August 1, 2015 to finance the Kemmerer Drop. The WMLP Term Loan Facility matures in December 2018. Borrowings under the WMLP Term Loan Facility are secured by substantially all of WMLP’s physical assets. Proceeds of the WMLP Loan were used to retire WMLP’s previously existing first and second lien credit facilities and to pay fees and expenses related to its existing credit facility, with the remaining proceeds being available as working capital.
As of December 31, 2015, the $299.2 million outstanding under the WMLP Term Loan Facility bears interest at a variable rate per annum equal to, at the WMLP’s option, LIBOR with a floor of 0.75% plus 8.50% or the Reference Rate (as defined in the WMLP Financing Agreement). As of December 31, 2015, the WMLP Term Loan Facility had a cash interest rate of 9.25%, consisting of the LIBOR floor of (0.75%) plus 8.5%.
The WMLP Term Loan Facility also provides for Paid-In-Kind Interest (“PIK Interest”) at a variable rate per annum between 1.00% and 3.00% based on WMLP’s total net leverage ratio. The rate of PIK Interest is recalculated on a quarterly basis with the PIK Interest added quarterly to the then outstanding principal amount of the term loan under the WMLP Term Loan Facility. PIK Interest under the WMLP Term Loan Facility was $6.9 million for the year ended December 31, 2015.
In connection with the Kemmerer Drop, the WMLP Term Loan Facility was amended on July 31, 2015 to (i) allow WMLP to make distributions in an aggregate amount not to exceed $15.0 million (previously $7.5 million) without pro forma compliance with the consolidated total net leverage ratio or fixed charge coverage ratio, and (ii) at any time that WMLP has a revolving loan facility available, require it to have liquidity of at least $7.5 million (previously $5.0 million), after giving effect to such distributions and applying availability under such revolving loan facility towards satisfying the liquidity requirement.
The WMLP Term Loan Facility contains customary financial and other covenants. As of December 31, 2015, WMLP was in compliance with all covenants under the terms of the WMLP Term Loan Facility, and we expect compliance with our covenants to continue.
Capital Leases
During the year ended December 31, 2015, we entered into $15.2 million of new capital leases.
Heritage Health Costs and Pension Contributions
Our liquidity continues to be affected by our heritage health and pension obligations as follows:
Historical Sources and Uses of Cash
The following table summarizes net cash provided by (used in) operating activities, investing activities, and financing activities for the twelve months ended December 31, 2015 and December 31, 2014.
Cash provided by operating activities is consistent year-over-year, while cash used in investing activities has decreased by $362.0 million primarily as a result of a decrease in cash payments related to acquisitions. Cash provided by financing activities decreased as a result of lower borrowings from long-term debt in order to finance our acquisitions in 2015 compared
to 2014. In the current year our cash flows were impacted by the following transactions:
These net cash outflows were offset by cash flows from operating activities, the proceeds from additional borrowings on the WCC Term Loan Facility, and proceeds from additional borrowings on the WMLP Term Loan Facility related to the Kemmerer Drop.
Contractual Obligations and Commitments
The following table presents information about our contractual obligations and commitments as of December 31, 2015, and the effects we expect such obligations to have on liquidity and cash flow in future periods. Some of the amounts below are estimates. We discuss these obligations and commitments elsewhere in this filing.
_____________________
(1)
Represents benefit payments for our postretirement medical benefits, black lung, workers’ compensation, and combined benefit fund plans, as well as contributions for our defined benefit pension plans and final reclamation costs.
Critical Accounting Policies and Estimates
The preparation of consolidated financial statements and related disclosures in conformity with accounting principles generally accepted in the United States of America requires management to make judgments, assumptions and estimates that affect the amounts reported. Note 1, “Summary of Significant Accounting Policies” of the Notes to the Consolidated Financial Statements in Item 8 of this Form 10-K describes the significant accounting policies and methods used in the preparation of the Company’s consolidated financial statements.
The policies and estimates discussed in this section are considered critical because they had or could have a material impact on our financial statements, and because they require significant judgments, assumptions or estimates. We base our estimates on historical experience and other assumptions that we believe to be reasonable under the circumstances. Actual results may differ from these estimates, and such differences could be material.
Postretirement Medical Benefits
We have an obligation to provide postretirement medical benefits to our former employees and their dependents. Detailed information related to this liability is included in Note 9 to our consolidated financial statements.
Our liability for our employees’ postretirement medical benefit costs is recorded on our consolidated balance sheets in amounts equal to the actuarially determined liability, as this obligation is not funded. We use various assumptions including the discount rate and future cost trends, to estimate the cost and obligation for this item. Our discount rate for postretirement medical benefit is determined by utilizing a hypothetical bond portfolio model, which approximates the future cash flows necessary to service our liability. This model is calculated using a yield curve that is developed using the average yield for bonds in the tenth to ninetieth percentiles, which excludes bonds with outlier yields. Our discount rates at December 31, 2015 ranged from 4.10% - 4.65% compared to a range of 3.75% - 4.25% at December 31, 2014.
Our medical care cost trend assumption is developed by annually examining the historical trend of our cost per claim data and projecting forward the participant claims and our current benefit coverage. If our assumptions do not materialize as expected, actual cash expenditures and costs that we incur could differ materially from our current estimates. Moreover, regulatory changes could increase our obligation to satisfy these or additional obligations.
The PPACA could potentially impact these benefits. The PPACA has both short-term and long-term implications on healthcare benefit plan standards. Implementation of this legislation is planned to occur in phases extending through 2018. We will continue to evaluate the impact of the PPACA in future periods as additional information, interpretations and guidance becomes available.
Below we have provided a sensitivity analysis to demonstrate the significance of the health care cost trend rate assumptions in relation to reported amounts.
Asset Retirement Obligations, Final Reclamation Costs and Reserve Estimates
Our asset retirement obligations primarily consist of cost estimates for final reclamation of surface land and support facilities at both surface mines and power plants in accordance with federal and state reclamation laws. Asset retirement obligations are based on projected pit configurations and are determined for each mine using estimates and assumptions including estimates of disturbed acreage as determined from engineering data, estimates of future costs to reclaim the disturbed acreage, the timing of these cash flows, and a credit-adjusted, risk-free rate. As changes in estimates occur such as mine plan revisions, changes in estimated costs, or changes in timing of the final reclamation activities, the obligation and asset are revised to reflect the new estimate after applying the appropriate credit-adjusted, risk-free rate to the changes. If our assumptions do not materialize as expected, actual cash expenditures and costs that we incur could be materially different from currently estimated. Moreover, regulatory changes could increase our obligation to perform final reclamation and mine closing activities.
Income Taxes and Deferred Income Taxes
The Company is subject to income taxes in the U.S. (including federal and state) and certain foreign jurisdictions. Deferred income taxes are provided for temporary differences arising from differences between the financial statement amount and tax basis of assets and liabilities existing at each balance sheet date using enacted tax rates anticipated to be in effect when the related taxes are expected to be paid or recovered. A valuation allowance is established if it is more likely than not (greater than 50%) that a deferred tax asset will not be realized. In determining the need for a valuation allowance at each reporting period, the Company considers projected realization of tax benefits based on expected levels of future taxable income, the duration of statutory carryforward periods, experience with operating loss and tax credit carryforwards not expiring and availability of tax planning strategies.
Accounting guidance prescribes a recognition threshold and measurement attribute for the financial statement recognition and measurement of a tax position taken or expected to be taken in a tax return. Under this guidance, a company can recognize the benefit of an income tax position only if it is more likely than not (greater than 50%) that the tax position will be sustained upon tax examination, based solely on the technical merits of the tax position. Guidance is also provided on the derecognition, classification, interest and penalties, accounting in interim periods, disclosure and transition.
As of December 31, 2015, the Company had significant deferred tax assets. The deferred tax assets include U.S. federal, state regular and foreign NOLs, AMT credit carryforwards, ICTC carryforwards, and net deductible reversing temporary differences related to on-going differences between book and taxable income. The Company has determined that since its net deductible temporary differences will not reverse for the foreseeable future, and it is unable to forecast that it will have regular taxable income when they do reverse, a full valuation allowance is required for these deferred tax assets.
Valuation of Long-Lived Assets
The carrying amount of long-lived tangible and intangible assets assets to be held and used in the business are reviewed for impairment when events or circumstances warrant such a review. Indicators of impairment include, but are not limited to: a significant change in the extent or manner in which an asset is used; a change in customer demand that could affect the value of the asset group; a significant decline in the observable market value of an asset group; or a significant adverse change in legal factors or in the business climate that could affect the value of the asset group.
Assets are grouped at the lowest level for which there are identifiable cash flows that are largely independent of the cash flows of other groups of assets. Coal mining assets are generally grouped at the mine level, and our ROVA operations also constitute an asset group.
When indicators of impairment are present, the Company evaluates its long-lived assets for recoverability by comparing the estimated undiscounted cash flows expected to be generated by those assets under various assumptions to their carrying amounts. If such undiscounted cash flows indicate that the carrying value of the asset group is not recoverable, impairment losses are measured by comparing the estimated fair value of the asset group to its carrying amount. Fair value is generally determined through the use of an expected present value technique based on the income approach. The estimated
future cash flows and underlying assumptions used to assess recoverability and, if necessary, measure the fair value of the Company's long-lived asset groups are derived from those developed in connection with the Company's planning and budgeting process. Our estimated future cash flows for our ROVA asset group also utilize projected power prices in addition to the estimated cash flows developed by our planning and budgeting process. The Company believes its assumptions to be consistent with those a market participant would use for valuation purposes.
For the year ended December 31, 2015 we recorded an impairment charge of $133.1 million related to our ROVA asset group, which is comprised of property, plant, and equipment used to generate electricity in our Power Segment primarily as a result of a continued decline in forecasted power prices. We also recorded a $3.1 million impairment charge related to certain long-lived assets at our Coal Valley mine due primarily to continued decreases in coal prices in the export market that the mine serves.
Business Combination Measurements
Acquisitions are accounted for under the acquisition method of accounting that requires the total purchase consideration to be allocated to the assets acquired and liabilities assumed based on estimates of fair value. During the measurement period (which is not to exceed one year from the acquisition date), additional assets or liabilities may be recognized if new information is obtained about facts and circumstances that existed as of the acquisition date that, if known, would have resulted in the recognition of those assets or liabilities as of that date. The preliminary allocation may be adjusted after obtaining additional information regarding, among other things, asset valuations, liabilities assumed and revisions of previous estimates. These adjustments may be significant and will be accounted for in the period they are identified.
Recent Accounting Pronouncements
See Note 1 of the Notes to the Consolidated Financial Statements in Item 8 of this Form 10-K for a full description of recent accounting pronouncements and our expectation of their impact on our Consolidated Financial Statements.
Off-Balance Sheet Arrangements
In the normal course of business, we are a party to certain off-balance sheet arrangements. These arrangements include financial instruments with off-balance sheet risk such as bank letters of credit and performance or surety bonds. We utilize surety bonds and letters of credit issued by financial institutions to third parties to assure the performance of our obligations relating to reclamation, workers’ compensation obligations, postretirement medical benefit obligations, and other obligations. These arrangements are not reflected in our consolidated balance sheets, and we do not expect any material adverse effects on our financial condition, results of operations or cash flows to result from these off-balance sheet arrangements.
We use a combination of surety bonds and letters of credit to secure our financial obligations for reclamation, workers’ compensation, postretirement medical benefit and other obligations as follows as of December 31, 2015:
ITEM 7A
ITEM 7A
- QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK.
We are exposed to market risk, which includes adverse changes in commodity prices and interest rates, and credit risk.
Commodity Price Risk
We are exposed to commodity price risk on sales of power at our ROVA facility. We have entered into derivative contracts to purchase power in the future at fixed prices. Such derivative contracts are structured to manage our exposure to changing power prices and not for trading. For the year ended December 31, 2015 and 2014, we incurred losses related to these derivative contracts of $5.6 million and $31.1 million, respectively. Since any resales which we may make in the open market under these derivative contracts would be made at prevailing market prices, we may be subject to further losses under these hedging arrangements in the event that the market price for power falls below the level of our hedged position. Based on current market pricing trends, we may experience further losses under these hedging arrangements before the market price for
power regains a level which is commensurate with our hedged position. If these trends continue, these losses could continue to adversely impact our results of operations and cash flows, and anticipated future cash losses are likely to be material. A sensitivity analysis has been performed to determine the incremental effect on future earnings related to open derivative instruments at December 31, 2015. A hypothetical 10 percent decrease in future power prices would decrease future earnings related to derivatives by $14.3 million. Similarly, a hypothetical 10 percent increase in future power prices would increase future earnings related to derivatives by $14.3 million.
We manage our price risk for coal sales through the use of long-term agreements, rather than through the use of derivatives. Nearly all of our coal is sold under long-term agreements. These coal contracts typically contain price escalation and adjustment provisions, pursuant to which the price for our coal may be periodically revised. The price may be adjusted 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.
For our coal contracts which are not cost protected, we have exposure to price risk for supplies that are used in the normal course of production such as diesel fuel and explosives. We manage these items through strategic sourcing contracts in normal quantities with our suppliers and may use derivatives from time to time. At December 31, 2015, we had fuel supply contracts outstanding with a minimum purchase requirement of 3.9 million gallons of diesel fuel per year. These contracts qualify for the normal purchase normal sale exception under hedge accounting.
Interest Rate Risk
We are exposed to market risk associated with interest rates due to our existing indebtedness that is indexed to either prime rate or LIBOR. Our WCC Term Loan Facility had an outstanding balance of $327 million as of December 31, 2015 and has interest rates that fluctuate based on changes in market rates. An increase in the interest rates related to the WCC Term Loan Facility of 100 basis points would result in an annualized increase of $1.7 million in interest expense based on interest rates in effect at December 31, 2015. A decrease of 100 basis points would not have an effect. We have not historically used interest rate hedging instruments to manage our interest rate risk.
Credit Risk
We are exposed to credit loss in the event of non-performance by our counterparties. We attempt to manage this exposure by entering into agreements with counterparties that meet our credit standards and that are expected to fully satisfy their obligations under the contracts. These steps may not always be effective in addressing counterparty credit risk.
Foreign Currency Exchange Rates
We are exposed to the effects of changes in exchange rates primarily from the Canadian dollar at our Canadian operations. To address the risks arising from adverse changes in foreign currency exchange rates from our planned cash flows in the Canadian Acquisition we entered into various derivative contracts. All decisions on derivative contracts are authorized and executed pursuant to our policies and procedures, which do not allow the use of financial instruments for trading purposes. There were no foreign currency derivative contracts outstanding as of December 31, 2015 and 2014.
ITEM 8
ITEM 8
-FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA.
Page
Report of Independent Registered Public Accounting Firm
Consolidated Balance Sheets
Consolidated Statements of Operations
Consolidated Statements of Comprehensive Income (Loss)
Consolidated Statements of Shareholders’ Deficit
Consolidated Statements of Cash Flows
Notes to Consolidated Financial Statements
Report of Independent Registered Public Accounting Firm
The Board of Directors and Shareholders of Westmoreland Coal Company and subsidiaries
We have audited the accompanying consolidated balance sheets of Westmoreland Coal Company and subsidiaries (the "Company") as of December 31, 2015 and 2014, and the related consolidated statements of operations, comprehensive income (loss), shareholders’ deficit, and cash flows for each of the three years in the period ended December 31, 2015. Our audits also included the financial statement schedule listed in the Index at Item 15(a). These financial statements and schedule are the responsibility of the Company's management. Our responsibility is to express an opinion on these financial statements based on our audits.
We conducted our audits in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.
In our opinion, the financial statements referred to above present fairly, in all material respects, the consolidated financial position of Westmoreland Coal Company and subsidiaries at December 31, 2015 and 2014, and the consolidated results of their operations and their cash flows for each of the three years in the period ended December 31, 2015 in conformity with U.S. generally accepted accounting principles. Also, in our opinion, the related financial statement schedule, when considered in relation to the basic financial statements taken as a whole, presents fairly in all material respects the information set forth therein.
We have also audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), the Company's internal control over financial reporting as of December 31, 2015, based on the criteria established in Internal Control-Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (2013 framework) and our report dated March 11, 2016 expressed an unqualified opinion thereon.
/s/ ERNST & YOUNG LLP
Denver, Colorado
March 11, 2016
WESTMORELAND COAL COMPANY AND SUBSIDIARIES
Consolidated Balance Sheets
See accompanying Notes to Consolidated Financial Statements.
WESTMORELAND COAL COMPANY AND SUBSIDIARIES
Consolidated Balance Sheets (Continued)
See accompanying Notes to Consolidated Financial Statements.
WESTMORELAND COAL COMPANY AND SUBSIDIARIES
Consolidated Statements of Operations
See accompanying Notes to Consolidated Financial Statements.
WESTMORELAND COAL COMPANY AND SUBSIDIARIES
Consolidated Statements of Comprehensive Income (Loss)
See accompanying Notes to Consolidated Financial Statements.
WESTMORELAND COAL COMPANY AND SUBSIDIARIES
Consolidated Statements of Shareholders’ Deficit
Years Ended December 31, 2013, 2014 and 2015
See accompanying Notes to Consolidated Financial Statements.
WESTMORELAND COAL COMPANY AND SUBSIDIARIES
Consolidated Statements of Cash Flows
See accompanying Notes to Consolidated Financial Statements.
WESTMORELAND COAL COMPANY AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
1. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES
Nature of Operations
Westmoreland Coal Company, or the Company, Westmoreland, WCC, or the Parent, is an energy company with our principal activities conducted within the United States and Canada. Our U.S. operations include the production and sale of coal from mines in Montana, North Dakota, Texas, and Ohio and the ownership of the Roanoke Valley power plants, or ROVA, in North Carolina. We also own the general partner of, and 93.8% of the total equity interest in, Westmoreland Resource Partners, LP (“WMLP”), a publicly traded limited partnership that owns and operates five coal mining complexes in Ohio and one coal mine in Wyoming. Our Canadian operations include the production and sale of coal from six surface mines in Alberta and Saskatchewan, selling char to the barbecue briquette industry, and a 50% interest in an activated carbon plant, which produces activated carbon for the removal of mercury from flue gas.
Consolidation Policy
The Consolidated Financial Statements of Westmoreland Coal Company include the accounts of the Company and its controlled subsidiaries. The Company provides for noncontrolling interests in consolidated subsidiaries in which the Company’s ownership is less than 100%. All intercompany accounts and transactions have been eliminated.
Investments in unconsolidated affiliates that the Company has the ability to exercise significant influence over, but not control, are accounted for under the equity method of accounting. Under the equity method of accounting, the Company records its proportionate share of the entity’s net income or loss at each reporting period in Income from equity affiliates on the Consolidated Statements of Operations with a corresponding entry to increase or decrease the carrying value of the investment. The Company’s 50% interest in the Estevan Activated Carbon Joint Venture is accounted for under the equity method of accounting.
Use of Estimates
The preparation of financial statements in conformity with Generally Accepted Accounting Principles (“GAAP”) requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosures of contingent assets and liabilities at the date of the financial statements and reported amounts of revenues and expenses during the reporting period. Actual results could differ from those estimates.
Cash and Cash Equivalents
Cash and cash equivalents are stated at cost, which approximate fair value. Cash equivalents consist of highly liquid investments with original maturities of three months or less.
Trade Receivables
Trade receivables are recorded at the invoiced amount and generally do not bear interest. The Company evaluates the need for an allowance for doubtful accounts based on a review of collectability. The Company has determined that no allowance is necessary for trade receivables as of December 31, 2015 or 2014.
Loan and Lease Receivables
The Company periodically executes loans and finance leases at the Genesee Mine with its only customer for purposes of funding capital expenditures and working capital requirements. Finance lease and loan receivables are measured at the present value of the future lease payments at the inception of the arrangement. Lease payments received are comprised of a repayment of principal and finance income. Finance income is recognized based on the interest rate implicit in the finance lease. We recognize finance income over periods between three and twenty-seven years, which reflect a constant periodic return on our net investment in the finance lease. Initial direct costs are included in the initial measurement of the finance lease receivables and reduce the amount of income recognized over the lease term.
Inventories
Inventories include materials and supplies, which are carried at historical cost less an obsolescence reserve when necessary, and raw coal, which is carried at the lower of cost or market. Cost of coal is determined using the average cost method and includes labor, supplies, equipment, depreciation, depletion, amortization, operating overhead and other related costs.
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Exploration and Mine Development
Exploration expenditures are charged to Cost of sales as incurred, including costs related to drilling and study costs incurred to convert or upgrade mineral resources to reserves.
At existing surface operations, additional pits may be added to increase production capacity in order to meet customer requirements. These expansions may require significant capital to purchase additional equipment, relocate equipment, build or improve existing haul roads and create the initial pre-production box cut to remove overburden for new pits at existing operations. If these pits operate in a separate and distinct area of the mine, the costs associated with initially uncovering coal for production are capitalized and amortized over the life of the developed pit consistent with coal industry practices. Once production has begun, mining costs are then expensed as incurred.
Where new pits are routinely developed as part of a contiguous mining sequence, the Company expenses such costs as incurred. The development of a contiguous pit typically reflects the planned progression of an existing pit, thus maintaining production levels from the same mining area utilizing the same employee group and equipment.
Property, Plant and Equipment
Property, plant and equipment are recorded at cost and includes long-term spare parts inventory. Expenditures that extend the useful lives of existing plant and equipment or increase productivity of the assets are capitalized. Maintenance and repair costs that do not extend the useful life or increase productivity of the asset are expensed as incurred. Coal reserves are recorded at cost, or at fair value originally in the case of acquired businesses.
Coal reserves, mineral rights and mine development costs are depleted based upon estimated recoverable proven and probable reserves. Long-term spare parts inventory begins depreciation when placed in service. Plant and equipment are depreciated on a straight-line basis over the assets’ estimated useful lives as follows:
When an asset is retired or sold, its cost and related accumulated depreciation and depletion are removed from the accounts. The difference between the net book value of the asset and proceeds on disposition is recorded as a gain or loss. Fully depreciated plant and equipment still in use is not eliminated from the accounts. Amortization of capital leases is included in Depreciation, depletion and amortization.
Impairment of Long-Lived Assets
The Company evaluates its long-lived assets held and used in operations for impairment as events and changes in circumstances indicate that the carrying amount of such assets might not be recoverable. Factors that would indicate potential impairment to be present include, but are not limited to, a sustained history of operating or cash flow losses, an unfavorable change in earnings and cash flow outlook, prolonged adverse industry or economic trends and a significant adverse change in the extent or manner in which a long-lived asset is being used or in its physical condition.
Assets are grouped at the lowest level for which there are identifiable cash flows that are largely independent of the cash flows of other groups of assets. Coal mining assets are generally grouped at the mine level, and our ROVA operations also constitute an asset group.
When indicators of impairment are present, the Company evaluates its long-lived assets for recoverability by comparing the estimated undiscounted cash flows expected to be generated by those assets under various assumptions to their carrying amounts. If such undiscounted cash flows indicate that the carrying value of the asset group is not recoverable, impairment losses are measured by comparing the estimated fair value of the asset group to its carrying amount. Fair value is generally determined through the use of an expected present value technique based on the income approach. The estimated future cash flows and underlying assumptions used to assess recoverability and, if necessary, measure the fair value of the Company's long-lived asset groups are derived from those developed in connection with the Company's planning and budgeting process. Our estimated future cash flows for our ROVA asset group also utilize projected power prices in addition to the estimated cash flows developed by our planning and budgeting process. The Company believes its assumptions to be consistent with those a market participant would use for valuation purposes.
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Reclamation Deposits and Contractual Third-Party Reclamation Receivables
Certain of the Company’s customers have either agreed to reimburse the Company for reclamation expenditures as they are incurred or have pre-funded a portion of the expected reclamation costs. Amounts received from customers and held on deposit are recorded as reclamation deposits. Amounts that are reimbursable by customers are recorded as third-party reclamation receivables when the related reclamation obligation is recorded.
Financial Instruments
The Company evaluates all of its financial instruments to determine if such instruments are derivatives, derivatives that qualify for the normal purchase normal sale exception or instruments that contain features that qualify them as embedded derivatives. Except for derivatives that qualify for the normal purchase normal sale exception, all derivative financial instruments are recognized in the balance sheet at fair value. Changes in fair value are recognized in earnings if they are not eligible for hedge accounting or Accumulated other comprehensive income (loss) if they qualify for cash flow hedge accounting.
Held-to-maturity financial instruments consist of non-derivative financial assets with fixed or determinable payments and a fixed term, which the Company has the ability and intent to hold until maturity, and, therefore, accounts for them as held-to-maturity securities. Held-to-maturity securities are recorded at amortized cost, adjusted for the amortization or accretion of premiums or discounts calculated on the effective interest method. Interest income is recognized when earned.
The Company has securities classified as available-for-sale, which are recorded at fair value. The changes in fair values are recorded as unrealized gains (losses) as a component of Accumulated other comprehensive income (loss) in shareholders’ deficit.
The Company reviews its securities routinely for other-than-temporary impairment. The primary factors used to determine if an impairment charge must be recorded because a decline in value of the security is other than temporary include (i) whether the fair value of the investment is significantly below its cost basis, (ii) the financial condition of the issuer of the security, (iii) the length of time that the cost of the security has exceeded its fair value and (iv) the Company’s intent and ability to retain the investment for a period of time sufficient to allow for any anticipated recovery in market value. Other-than-temporary impairments are recorded as a component of Other income.
Fair Value
Fair value is the price that would be received to sell an asset or paid to transfer a liability in an orderly transaction between market participants at a given measurement date. Valuation techniques used must maximize the use of observable inputs and minimize the use of unobservable inputs.
The fair value hierarchy prioritizes the inputs to valuation techniques used to measure fair value and is defined as:
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Level 1, defined as observable inputs such as quoted prices in active markets for identical assets. Level 1 assets include available-for-sale equity securities generally valued based on independent third-party market prices.
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Level 2, defined as observable inputs other than Level 1 prices. These include quoted prices for similar assets or liabilities in an active market, quoted prices for identical assets and liabilities in markets that are not active, or other inputs that are observable or can be corroborated by observable market data for substantially the full term of the assets or liabilities.
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Level 3, defined as unobservable inputs in which little or no market data exists, therefore requiring an entity to develop its own assumptions.
Intangible Assets and Liabilities
Identifiable intangible assets or liabilities acquired in a business combination are recognized and reported separately from goodwill.
Workers’ Compensation Benefits
The Company is self-insured for workers’ compensation claims incurred prior to 1996. The liabilities for workers’ compensation claims are actuarially determined estimates of the ultimate losses incurred based on the Company’s experience. Adjustments to the actuarially determined liability are made annually based on subsequent developments and experience and are included in operations at the time of the revised estimate.
The Company insures its current employees through third-party insurance providers and state arrangements.
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Pneumoconiosis (Black Lung) Benefits
The Company is self-insured for federal and state black lung benefits for former heritage employees and has established an independent trust to pay these benefits. The Company accounts for these benefits on the accrual basis. An independent actuary annually calculates the present value of the accumulated black lung obligation. The underfunded status in 2015 and 2014 of the Company’s obligation is included as Excess of black lung benefit obligation over trust assets
in the accompanying consolidated balance sheets. Actuarial gains and losses are recognized in the period in which they arise.
The Company insures its current represented employees through arrangements with its unions and its current non-represented employees are insured through third-party insurance providers. The Company maintains actuarially determined accruals to account for estimates of the ultimate losses incurred.
Postretirement Health Care Benefits
The Company accrues the cost to provide the benefits over the employees’ period of active service for postretirement benefits other than pensions. These costs are determined on an actuarial basis. The Company’s consolidated balance sheet reflects the unfunded status of postretirement benefit obligations.
Pension and SERP Plans
The Company accrues the cost to provide the benefits over the employees’ period of active service for the non-contributory defined benefit pension and SERP plans it sponsors. These costs are determined on an actuarial basis. The Company’s consolidated balance sheet reflects the unfunded status of the defined benefit pension and SERP plans.
Deferred Revenue
Deferred revenues represent funding received in advance of meeting the criteria for revenue recognition. Deferred revenue is recognized as the underlying revenue recognition criteria are met, which often occurs as deliveries of coal or power are made in accordance with long-term contacts.
Asset Retirement Obligations
The Company’s asset retirement obligation, or ARO, liabilities primarily consist of estimated costs to reclaim surface land and support facilities at its mines and power plants in accordance with federal and state reclamation laws as established by each mining permit.
The Company estimates its ARO liabilities for final reclamation and mine closure based upon detailed engineering calculations of the amount and timing of the future costs for a third party to perform the required work. These estimates are based on projected pit configurations and are escalated for inflation, and then discounted at a credit-adjusted risk-free rate. The Company records mineral rights associated with the initial recorded liability. Mineral rights are amortized based on the units of production method over the estimated recoverable, proven and probable reserves at the related mine, and the ARO liability is accreted to the projected settlement date. Changes in estimates could occur due to revisions of mine plans, changes in estimated costs, and changes in timing of the performance of reclamation activities.
Income Taxes
The Company is subject to income taxes in the U.S. (including federal and state) and certain foreign jurisdictions. Deferred income taxes are provided for temporary differences arising from differences between the financial statement amount and tax basis of assets and liabilities existing at each balance sheet date using enacted tax rates anticipated to be in effect when the related taxes are expected to be paid or recovered. A valuation allowance is established if it is more likely than not (greater than 50%) that a deferred tax asset will not be realized. In determining the need for a valuation allowance at each reporting period, the Company considers projected realization of tax benefits based on expected levels of future taxable income, the duration of statutory carryforward periods, experience with operating loss and tax credit carryforwards not expiring and availability of tax planning strategies.
Accounting guidance prescribes a recognition threshold and measurement attribute for the financial statement recognition and measurement of a tax position taken or expected to be taken in a tax return. Under this guidance, a company can recognize the benefit of an income tax position only if it is more likely than not (greater than 50%) that the tax position will be sustained upon tax examination, based solely on the technical merits of the tax position. Guidance is also provided on the derecognition, classification, interest and penalties, accounting in interim periods, disclosure and transition.
The Company includes interest and penalties related to income tax matters in income tax expense. Deferred tax liabilities and assets are classified as noncurrent in the statement of financial position.
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The tax effect of pretax income or loss from continuing operations is generally determined by a computation that does not consider the tax effects of items that are not included in continuing operations. The exception to that incremental approach is that all items (for example, items recorded in other comprehensive income, extraordinary items, and discontinued operations) be considered in determining the amount of tax benefit that results from a loss from continuing operations and that shall be allocated to continuing operations.
Deferred Financing Costs
The Company capitalizes costs incurred in connection with borrowings or establishment of credit facilities and issuance of debt securities. These costs are amortized as an adjustment to interest expense over the life of the borrowing or term of the credit facility using the effective interest method. These amounts are recorded in Other assets in the accompanying consolidated balance sheets.
Coal Revenues
The Company recognizes coal sales revenue at the time title passes to the customer in accordance with the terms of the underlying sales agreements and after any contingent performance obligations have been satisfied. Coal sales revenue is recognized based on the pricing contained in the contracts in place at the time that title passes.
Power Revenues
ROVA supplies power it produces and generates revenues from such sales, as well as through the settlement of related purchased power arrangements. A portion of the payment under the power sales agreement is considered to be an operating lease. The Company is recognizing amounts previously invoiced as revenue on a pro rata basis over the remaining term of the power sales agreement.
Other Operating Income (Loss)
Other operating income in the accompanying Consolidated Results of Operations reflects income from sources other than coal or power revenues. Income from the Company’s Indian Coal Tax Credit monetization transaction is recorded as Other operating income. The Company recognizes other operating income when business interruption losses have been incurred and reimbursement is realized or realizable. Insurance proceeds are included in Net cash provided by operating activities when received.
Share-Based Compensation
Share-based compensation expense is generally measured at the grant date and recognized as expense over the vesting period of the entire award. These costs are recorded in Cost of sales and Selling and administrative expenses in the accompanying consolidated results of operations.
Earnings (Loss) per Share
Basic earnings (loss) per share have been computed by dividing the net income (loss) applicable to common shareholders by the weighted average number of shares of common stock outstanding during each period. Net income (loss) applicable to common shareholders includes the adjustment for net income or loss attributable to the noncontrolling interest. Diluted earnings (loss) per share is computed by including the dilutive effect of common stock that would be issued assuming conversion or exercise of outstanding convertible notes, stock options, stock appreciation rights, restricted stock and warrants. No such items were included in the computation of diluted loss per share for the years ended 2015, 2014 or 2013 because the Company incurred a loss from operations in each of these periods and the effect of inclusion would have been anti-dilutive.
The table below shows the number of shares that were excluded from the calculation of diluted loss per share because their inclusion would be anti-dilutive to the calculation:
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Derivatives
The Company enters into financial derivatives to manage exposure to fluctuations in foreign currency exchange rates and power prices. The Company does not utilize derivative financial instruments for trading purposes or for speculative purposes.
The Company’s derivative instruments are recorded at fair value with changes in fair value recognized in the Consolidated Statements of Operations at the end of each period in Gain (loss) on foreign exchange or Derivative loss.
Foreign Exchange Transactions
Amounts held and transactions denominated in foreign currencies other than the operating unit’s functional currency give rise to foreign exchange gains and losses which are included within Gain (loss) on foreign exchange.
Foreign Currency Translation
The functional currency of the Company’s Canadian operations is the Canadian dollar. The Company’s Canadian operations’ assets and liabilities are translated at period end exchange rates, and revenues and costs are translated using average exchange rates for the period. Foreign currency translation adjustments are reported in Other comprehensive income (loss).
Reclassifications
Certain amounts in prior periods have been reclassified to conform with the presentation of 2015, with no effect on previously reported net loss, cash flows or shareholders’ deficit.
Recently Adopted Accounting Pronouncements
In September 2015, the Financial Accounting Standards Board, or FASB, issued Accounting Standard Update (“ASU”) 2015-16, Business Combinations (Topic 805): Simplifying the Accounting for Measurement-Period Adjustments. ASU 2015-16 eliminates the requirement that an acquirer in a business combination account for measurement-period adjustments retrospectively. Instead, an acquirer will recognize a measurement-period adjustment during the period in which it determines the amount of the adjustment. The guidance is effective for public business entities for fiscal years beginning after 15 December 2015, and interim periods within those fiscal years. Early adoption is permitted. We early adopted this guidance during 2015, with no material impact to our financial statements.
In November 2015, the FASB issued ASU 2015-17, Income Taxes (Topic 740): Balance Sheet Classification of Deferred Taxes. ASU 2015-17 simplifies the presentation of deferred income taxes by requiring that deferred tax liabilities and assets be classified as noncurrent in a classified statement of financial position. The guidance is effective for financial statements issued for annual periods beginning after December 15, 2016, and interim periods within those annual periods with early adoption permitted. We elected to early adopt this standard on December 31, 2015 and retrospectively apply the guidance to prior periods to allow for better comparison. This change in accounting principle had the effect of reducing the non-current liability Deferred income taxes by $13.1 million and $5.4 million as of December 31, 2014 and 2013, respectively. The current asset Deferred income taxes was also reduced to zero for each year by the same amounts.
Accounting Pronouncements Effective in the Future
In May 2014, the FASB issued ASU 2014-09, Revenue From Contracts With Customers, which outlines a single comprehensive model for entities to use in accounting for revenue arising from contracts with customers and supersedes most current revenue recognition guidance, including industry-specific guidance. The ASU is based on the principle that an entity should recognize revenue to depict the transfer of goods or services to customers in an amount that reflects the consideration which the entity expects to be entitled to receive in exchange for those goods or services. The ASU also requires additional disclosure about the nature, amount, timing and uncertainty of revenue and cash flows arising from customer contracts, including significant judgments and changes in judgments and assets recognized from costs incurred to fulfill a contract. Entities have the option of using either a full retrospective or a modified retrospective approach for the adoption of the new standard. In April 2015, the FASB agreed to propose a one-year deferral of the revenue recognition standard's effective date. The new guidance is now effective for the interim and annual periods beginning after December 15, 2017; early application is permitted, but not before the original effective date (annual reporting periods beginning after December 15, 2016). We are currently assessing the impact that this standard will have on our consolidated financial statements and plan to adopt the guidance by its effective date.
In August 2014, the FASB issued ASU 2014-15, Presentation of Financial Statements-Going Concern (Subtopic 205-40): Disclosure of Uncertainties about an Entity’s Ability to Continue as a Going Concern, which is intended to define
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management’s responsibility to evaluate whether there is substantial doubt about an organization’s ability to continue as a going concern and to provide related footnote disclosures. The new guidance is effective for the interim and annual periods beginning after December 15, 2016; early adoption is permitted for annual or interim reporting periods for which the financial statements have not previously been issued. We anticipate expanded going concern related disclosures to address this guidance in the year it becomes effective.
In April 2015, the FASB issued ASU 2015-03, Interest - Imputation of Interest (Subtopic 835-30): Simplifying the Presentation of Debt Issuance Costs, which requires that debt issuance costs related to a recognized liability be presented in the balance sheet as a direct deduction from the carrying amount of that debt liability, consistent with debt discounts. The new guidance should be applied on a retrospective basis and is effective for financial statements issued for fiscal years beginning after December 15, 2015, and interim periods within those fiscal years, with early adoption permitted. Management projects the impact to the financial statements resulting in balance sheet reclassification reducing the Long-term debt, less current installments balance for each of the respective periods upon adoption.
In April 2015, the FASB issued ASU 2015-05, Internal-Use Software (Subtopic 350-40): Customer's Accounting for Fees Paid in a Cloud Computing Arrangement, which provides guidance for determining whether a cloud computing arrangement (also referred to as a hosting arrangement) has a software license element and provides guidance on the appropriate accounting treatment. The new guidance should be applied on a retrospective basis. The new guidance is effective for financial statements issued for fiscal years beginning after December 15, 2015, and interim periods within those fiscal years, with early adoption permitted. The Company is currently evaluating the effect that adopting this new accounting guidance will have on its consolidated results of operations, cash flows and financial position and does not believe its impact will be material.
In February 2016, the FASB issued ASU No. 2016-02, "Leases" (Topic 842) ("ASU 2016-02"). The amendments in ASU 2016-02 require companies that lease assets to recognize on their balance sheets the assets and liabilities for the rights and obligations generated by contracts longer than one year. ASU 2016-02 is effective for fiscal years beginning after December 15, 2018 with early adoption permitted. The guidance is required to be applied by the modified retrospective transition approach. Early adoption is permitted. We are currently evaluating the potential impact adopting ASU 2016-02 will have on our consolidated financial statements and footnote disclosures.
2. ACQUISITIONS
Acquisition of Buckingham Coal Company, LLC
On January 1, 2015, Westmoreland completed the acquisition of Buckingham Coal Company, LLC, an Ohio-based coal supplier (“Buckingham”), pursuant to an agreement dated January 1, 2015 among WCC Land Holding Company, Inc., an affiliate of the Company, for a total cash purchase price of $32.5 million (the “Buckingham Acquisition”). The Buckingham Acquisition has been accounted for under the acquisition method of accounting that requires the total purchase consideration to be allocated to the assets acquired and liabilities assumed based on estimates of fair value. Of the total purchase price, $26.8 million was allocated to property plant and equipment, $12.1 million to land and mineral reserves and $6.4 million to net liabilities assumed. The Buckingham operations are included in the Company’s Coal - U.S. segment. Purchase price accounting was considered final as of December 31, 2015.
Acquisition of General Partner of Westmoreland Resource Partners, LP
On December 31, 2014, the Company completed the acquisition of Oxford Resources GP, LLC, the general partner of Oxford Resource Partners, LP, for $33.5 million in cash consideration (the “GP Acquisition”). Also on December 31, 2014 the Company completed a contribution of certain royalty-bearing coal reserves in return for 4,512,500 common units of Oxford Resource Partners, LP (the “Contribution”). In connection with these transactions, Oxford Resources GP, LLC was renamed to Westmoreland Resources GP, LLC, and Oxford Resource Partners, LP was renamed to Westmoreland Resource Partners, LP (“WMLP”). WMLP will continue to operate as a standalone, publicly traded master limited partnership, with common units trading on the NYSE under the symbol WMLP.
The completion of the GP Acquisition and the Contribution provide Westmoreland with a platform to implement a value-creating drop-down strategy, pursuant to which it intends to periodically contribute certain U.S. and Canadian coal assets to WMLP in exchange for a combination of cash and additional limited partner interests. After completion of the GP Acquisition and the Contribution, the Company owned approximately 79% of the fully diluted limited partner interests as of December 31, 2014 which increased by December 31, 2015 to 93.8% as a result of the Kemmerer Drop, described below. WMLP resumed quarterly distributions of $0.20 per unit beginning in April 2015. In addition to receiving our proportionate share of these distributions, as WMLP's general partner, the Company is entitled to incentive distribution rights.
Acquisition related costs of $0.3 million and $4.5 million have been expensed for the years ended December 31, 2015 and 2014 which are included in Selling and administrative costs.
The acquisition of the GP has been accounted for under the acquisition method of accounting that requires the total purchase consideration to be allocated to the assets acquired and liabilities assumed based on estimates of fair value. The Company has finalized the purchase price allocation for the GP acquisition, summarized as follows (in millions):
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No goodwill was recorded in the acquisition and a $31.0 million intangible asset related to a favorable terminal lease at a dock in Ohio will be amortized over a fifteen-year period. The favorable lease was valued based on the difference between contracted prices and market prices.
Kemmerer Drop
On August 1, 2015, we contributed 100% of the outstanding equity interests in Westmoreland Kemmerer, LLC (“Kemmerer”) to WMLP in exchange for $230 million in aggregate consideration, comprised of $115 million in cash and $115 million in newly issued WMLP Series A Convertible Units (the “Series A Units” and such transaction, the “Kemmerer Drop”). In connection with the Kemmerer Drop, all employees of Kemmerer and related employee liabilities, including but not limited to post-retirement pension obligations and post-retirement health benefits, were transferred to us. The Series A Units are convertible into common units representing limited partner interests of WMLP (“Common Units”), on a one-for-one basis, upon the earlier of (i) the date on which WMLP first makes a regular quarterly cash distribution to holders of Common Units in an amount equal to at least $0.22 per Common Unit, or (ii) a change of control of WMLP. Following the Kemmerer Drop, we hold an approximately 93.8% controlling interest in WMLP (on a fully diluted basis). The Kemmerer Drop represents a reorganization of entities under common control. Accordingly, the net assets transferred are deemed to have transferred at the $102.6 million carrying value as of the date of transfer. No gain or loss was recognized.
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Canadian Acquisition
On April 28, 2014, the Company acquired Sherritt International Corporation’s coal mining operations (the “Canadian Acquisition”) which include six producing thermal coal mines in the Canadian provinces of Alberta and Saskatchewan, a char production facility, and a 50% interest in an activated carbon plant. The purchase consideration included a $282.8 million initial cash payment made on April 28, 2014, a cash payment for a working capital adjustment of $39.8 million made on June 25, 2014, and assumed liabilities of $421.3 million.
Acquisition related costs of $33.6 million have been expensed for the year ended December 31, 2014 which included a $14.2 million charge to Cost of sales related to the post-close sale of inventory written up to fair value in the acquisition, $8.3 million of expenses included in Selling and administrative costs, $6.2 million of loss on foreign exchange and $4.9 million included in Interest expense related to a bridge facility commitment fee.
The Canadian Acquisition has been accounted for under the acquisition method of accounting that requires the total purchase consideration to be allocated to the assets acquired and liabilities assumed based on estimates of fair value. The Company has finalized the purchase price allocation for the Canadian Acquisition, summarized as follows (in millions):
The $26.2 million of cash and cash equivalents noted above includes $18.1 million which was used for immediate payment of an assumed liability on the acquisition date, leaving $8.1 million of net cash received upon the acquisition.
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During the third quarter of 2014, the Company transferred to an unrelated third party the contract related to the $37.0 million intangible asset noted above. Proceeds of $37.0 million were received from the unrelated third party, with no gain or loss recognized on the transaction.
As part of the Canadian Acquisition the Company became responsible for remediation work for a breach on a containment pond at a currently inactive mine that occurred on October 31, 2013. Sherritt has indemnified Westmoreland against past and future liability stemming from the incident. Accordingly, an indemnification asset of $27.9 million and a corresponding liability was recorded at April 28, 2014.
The results of the acquired operations subsequent to April 28, 2014 have been included in the Company’s consolidated results of operations.
Unaudited Pro Forma Information
The following unaudited pro forma information has been prepared for illustrative purposes only and assumes the acquisition of the GP and the Canadian Acquisition occurred on January 1, 2013. The unaudited pro forma results have been prepared based on estimates and assumptions, which the Company believes are reasonable, however, they are not necessarily indicative of the consolidated results of operations had the acquisitions occurred on January 1, 2013, or of future results of operations. Unaudited pro forma information for 2015 is not presented as a result of all acquired entities being consolidated for the entire year.
3. LOSS ON IMPAIRMENT
During the fourth quarter of 2015 we evaluated our ROVA asset group for impairment primarily as a result of an impairment indicator related to the continued decline in forecasted electricity prices. The asset group is comprised of property, plant, and equipment and related capital spares used to generate electricity, and resides in our Power segment. Our evaluation concluded that the long-lived assets at ROVA were impaired, and the carrying value of those assets was written down to zero as a result of an impairment charge of $133.1 million, with the charge included in the Loss on Impairment line item on the Consolidated Statement of Operations for the year ended December 31, 2015. Our fair value measurement for these assets was determined based on a probability-weighted estimate of discounted future cash flows, which are Level 3 fair value measurements. Key inputs to the fair value measurement for these assets included current forecasted electricity prices in the region ROVA serves, which we believe will continue to remain at depressed levels, as well as forecasted cost inputs based on the Company’s planning and budgeting process.
We also recorded an impairment charge of $3.1 million to the same line item on the Consolidated Statement of Operations during the year ended December 31, 2015 for certain immovable fixed assets at our Coal Valley mine, which is part
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of the Coal-Canada segment, primarily as a result of continued declines in pricing in the export markets which Coal Valley serves.
4. INVENTORIES
Inventories consisted of the following:
5. RESTRICTED INVESTMENTS AND BOND COLLATERAL
The Company’s restricted investments and bond collateral consist of the following:
Coal Segments
The coal segments maintain government-required bond collateral of individual mines which assures that coal-mining operations comply with applicable federal and state regulations relating to the performance and completion of final reclamation activities. The amounts deposited in the bond collateral account secure the bonds issued by the bonding company.
Power Segment
The power segment is required to maintain a collateral account related to its contracts to purchase power.
Corporate Segment
The Company is required to obtain surety bonds in connection with its self-insured workers’ compensation plan and certain health care plans. The Company’s surety bond underwriters require collateral to issue these bonds.
Funds in the restricted investments and bond collateral accounts are not available to meet the Company’s general cash needs. The Company can invest its restricted investments and bond collateral in a limited selection of fixed-income investment options and receive the related investment returns.
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These accounts include available-for-sale securities. Available-for-sale securities are reported at fair value with unrealized gains and losses excluded from earnings and reported in Accumulated other comprehensive loss. On disposal, the cost basis of an investment sold is specifically identified, and the resulting gain or loss is reported in Other income.
The Company’s carrying value and estimated fair value of its restricted investments and bond collateral at December 31, 2015 are as follows:
Available-for-Sale Restricted Investments and Bond Collateral
Available-for-sale restricted investments and bond collateral were as follows:
Maturities of available-for-sale securities were as follows at December 31, 2015:
In 2015, 2014, and 2013, the Company recorded gains of $0.1 million, $0.3 million, and less than $0.1 million, respectively, on the sale of available-for-sale securities held as restricted investments and bond collateral.
6. INTANGIBLE ASSETS AND LIABILITIES
Our intangible assets resulted from our acquisition, as part of a business combination, of contracts with terms that are favorable to prevailing market prices at the time of acquisition. Amortization of intangible assets recognized in Cost of sales was zero in 2015, $1.2 million in 2014 and $1.7 million in 2013.
Our intangible liabilities resulted from our acquisition, as part of a business combination, of contracts with terms that are unfavorable to prevailing market prices at the time of acquisition. Amortization of intangible liabilities recognized in Revenues was $1.0 million in 2015, 2014, and 2013.
The intangible assets and liabilities are generally amortized straight-line over the life of the related contract. The estimated amortization amounts from intangibles assets and liabilities for each of the next five years as of December 31, 2015 are as follows:
WESTMORELAND COAL COMPANY AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONT.)
7. RESTRUCTURING CHARGES
In 2013, the Company entered into an agreement with Virginia Power to renegotiate the remaining five years of the ROVA contract (the “ROVA Restructuring Plan”). Total restructuring charges related to the ROVA Restructuring Plan were $5.5 million and all were recorded to the restructuring expense line item within our consolidated statements of operations as they were incurred. Restructuring expenses related to the ROVA Restructuring Plan impacted our Power Segment and all actions related to this restructuring plan have been completed.
During 2014, the Company initiated strategic changes related to the Canadian Acquisition and the GP Acquisition (collectively, the “Acquisition Restructuring Plans”). Total expected restructuring charges related to the Acquisition Restructuring Plans of $15.2 million have been recorded to the restructuring expense line item within our consolidated statements of operations as they were incurred. Charges related to the Acquisition Restructuring Plans were comprised of one-time employee termination benefits and impacted all segments except for our Power Segment. The table below represents the restructuring provision activity related to the restructuring plans (in millions):
8. LINES OF CREDIT AND LONG-TERM DEBT
The amounts outstanding under the Company’s long-term debt consisted of the following as of the dates indicated:
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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONT.)
The following table presents aggregate contractual debt maturities of all long-term debt:
8.75% Notes due 2022 (the “8.75% Notes”)
On December 16, 2014 (the “Closing Date”), the Company completed the issuance of $350.0 million in aggregate principal amount of 8.75% Notes. The 8.75% Notes were issued at a 1.292% discount, mature on January 1, 2022, and bear a fixed interest rate of 8.75% payable semiannually, on January 1 and July 1 of each year, commencing July 1, 2015. The 8.75% Notes are the Company’s senior secured obligations, rank equally in right of payment with all of the Company’s existing and future senior obligations, including the WCC Term Loan Facility defined below under “WCC Term Loan Facility,” and rank senior to all of the Company’s existing and future indebtedness that is expressly subordinated to the 8.75% Notes. The 8.75% Notes have not been registered under the Securities Act of 1933. In 2014, the Company capitalized debt issuance costs of $10.2 million in connection with the 8.75% Notes.
The Company may redeem all or part of the 8.75% Notes beginning on January 1, 2018 at the redemption prices set forth in the 8.75% Notes agreement, and prior to January 1, 2018 at 100% of the principal amount plus the applicable premium described in the 8.75% Notes agreement. In addition, at any time prior to January 1, 2018, the Company may redeem up to 35% of the aggregate principal amount of the 8.75% Notes with the net cash proceeds of certain equity offerings at a redemption price equal to 108.75% of the principal amount to be redeemed, together with accrued and unpaid interest, if any, to the redemption date, subject to certain conditions.
The 8.75% Notes are guaranteed by Westmoreland Energy LLC, Westmoreland Mining LLC and Westmoreland Resources, Inc. and their respective subsidiaries (other than Absaloka Coal, LLC, Westmoreland Risk Management, Inc. and certain other immaterial subsidiaries). The 8.75% Notes are not guaranteed by Westmoreland Canada LLC or any of its subsidiaries, nor are they guaranteed by Westmoreland Resources GP, LLC or Westmoreland Resource Partners, LP or any of its subsidiaries, referred to as the Non-guarantors.
The 8.75% Notes and the guarantees are secured equally and ratably with the WCC Term Loan Facility (i) by first priority liens on substantially all of the Company’s and the guarantor parties’ tangible and intangible assets (excluding certain equity interests, mineral rights and sales contracts and certain assets subject to existing liens) and (ii) subject to the WCC Revolving Credit Facility (as defined below), a second priority lien on substantially all cash, accounts receivable and inventory of the Company and the guarantors, and any other property with respect to, evidencing or relating to such cash, accounts receivable and inventory (whether now owned or hereinafter arising or acquired) and the proceeds and products thereof, subject in each case to permitted liens and certain exclusions (the “Notes Collateral”). The Notes Collateral is shared equally with the lenders under the WCC Term Loan Facility, who hold identical first and second priority liens, as applicable, on the Notes Collateral.
The 8.75% Notes restrict the Company’s and its restricted subsidiaries’ ability to, among other things, (i) incur, assume or guarantee additional indebtedness or issue preferred stock; (ii) declare or pay dividends on, or make other distributions in respect of, their capital stock; (iii) purchase or redeem or otherwise acquire for value any capital stock or subordinated indebtedness; (iv) make investments, other than permitted investments; (v) create certain liens or use assets as security; (vi) enter into agreements restricting the ability of any restricted subsidiary to pay dividends, make loans, or any other distributions to the Company or other restricted subsidiaries; (vii) engage in transactions with affiliates; and (viii) consolidate or merge with or into other companies or transfer all or substantially all of their assets.
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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONT.)
The 8.75% Notes contains, among other provisions, events of default and various affirmative and negative covenants. As of December 31, 2015, the Company was in compliance with all covenants for the 8.75% Notes.
WCC Term Loan Facility due 2020
Effective as of the Closing Date, the Company entered into a WCC Term Loan Facility which provided for a $350.0 million term loan facility with a single advance made on the Closing Date. The WCC Term Loan Facility was issued at a 2.5% discount and matures on December 16, 2020. Borrowings under the WCC Term Loan Facility initially bear interest at one-month London Interbank Offered Rate (“LIBOR”) plus 6.50%. The interest rate at December 31, 2015 was 7.50%. In 2014, the Company capitalized debt issuance costs of $8.4 million in connection with the WCC Term Loan Facility.
The WCC Term Loan Facility contains customary affirmative covenants, negative covenants, and events of default. Pursuant to the terms and provisions of the Guaranty and Collateral Agreement, dated the Closing Date, the obligations under the WCC Term Loan Facility are secured by identical first and second priority liens, as applicable, on the Notes Collateral. As of December 31, 2015, the Company was in compliance with all covenants for the WCC Term Loan Facility.
The WCC Term Loan Facility is guaranteed by Westmoreland Energy LLC, Westmoreland Mining LLC, Westmoreland Resources, Inc. and certain other direct and indirect subsidiaries of the Company (other than Absaloka Coal, LLC, Westmoreland Risk Management, Inc., Westmoreland Canada, LLC, Westmoreland Resources GP, LLC, Westmoreland Resource Partners, LP and certain other immaterial subsidiaries).
WCC Term Loan Facility Add-on
On January 22, 2015, the Company amended the WCC Term Loan Facility to increase the borrowings by $75.0 million, for an aggregate principal amount of $425.0 million as of that date. The amendments to the WCC Term Loan Facility were made in connection with the acquisition of Buckingham Coal Company, LLC. Net proceeds were $71.0 million after a 2.5% discount, 1.5% broker fee, a consent fee of 1.17%, and $0.1 million of additional debt issuance costs.
In conjunction with the Kemmerer Drop, the Company amended the WCC Term Loan Facility to remove Kemmerer as a guarantor. In addition, $94.1 million of the proceeds received from WMLP related to the Kemmerer Drop were used to pay down the WCC Term Loan Facility.
WMLP Term Loan Facility due 2018
On December 31, 2014, WMLP entered into a WMLP Term Loan Facility which consists of a $175.0 million term loan, with an option for an additional $120.0 million in term loans for acquisitions, which was exercised on August 1, 2015 to finance the Kemmerer Drop. The WMLP Term Loan Facility matures in December 2018. Borrowings under the WMLP Term Loan Facility are secured by substantially all of WMLP’s physical assets. Proceeds from the credit facility were used to retire WMLP’s previously existing first and second lien credit facilities and to pay fees and expenses related to its existing credit facility, with the remaining proceeds being available as working capital.
As of December 31, 2015, the $299.2 million outstanding under the WMLP Term Loan Facility bears interest at a variable rate per annum equal to, at the WMLP’s option, the LIBOR floor of 0.75% plus 8.5% or the Reference Rate (as defined in the WMLP Financing Agreement). As of December 31, 2015, the WMLP Term Loan Facility had a cash interest rate of 9.25%, consisting of the LIBOR floor (0.75%) plus 8.5%.
The WMLP Term Loan Facility also provides for Paid-In-Kind Interest (“PIK Interest”) at a variable rate per annum between 1.00% and 3.00% based on WMLP’s total net leverage ratio. The rate of PIK Interest is recalculated on a quarterly basis with the PIK Interest added quarterly to the then outstanding principal amount of the term loan under the WMLP Term Loan Facility. PIK Interest under the WMLP Term Loan Facility was $6.9 million for the year ended December 31, 2015.
In connection with the Kemmerer Drop, the WMLP Term Loan Facility was amended on July 31, 2015 to (i) allow WMLP to make distributions in an aggregate amount not to exceed $15.0 million (previously $7.5 million) without pro forma compliance with the consolidated total net leverage ratio or fixed charge coverage ratio, and (ii) at any time that WMLP has a revolving loan facility available, require it to have liquidity of at least $7.5 million (previously $5.0 million), after giving effect to such distributions and applying availability under such revolving loan facility towards satisfying the liquidity requirement.
The WMLP Term Loan Facility contains customary financial and other covenants. As of December 31, 2015, WMLP was in compliance with all covenants under the terms of the WMLP Term Loan Facility.
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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONT.)
The WCC Revolving Credit Facility
During the first quarter of 2014, the Company amended its WCC Revolving Credit Facility, or Revolver, to increase the maximum available borrowing amount to $60.0 million. On December 16, 2014, the Company further amended the WCC Revolving Credit Facility, decreasing the maximum borrowing amount to $50.0 million in the aggregate, consisting of a $30.0 million sub-facility available in the U.S. and a $20.0 million sub-facility available in Canada. Pursuant to a June 2, 2015 amendment to the WCC Revolving Credit Facility, Westmoreland has a total aggregate borrowing capacity of $75.0 million between June 15th and August 15 of each year. The Revolver may support an equal amount of letters of credit, which would reduce the balance available under the Revolver. At December 31, 2015, availability under the WCC Revolving Credit Facility was $28.2 million with an outstanding balance of $19.8 million supporting letters of credit and a $2.0 million drawn on the revolver. All extensions of credit under the revolver are collateralized by a first priority security interest in and lien upon the inventory and accounts receivable of substantially all of the Company’s subsidiaries (other than Absaloka Coal, LLC, Westmoreland Risk Management, Inc.,Westmoreland Resources GP, LLC, Westmoreland Resource Partners, LP and certain other immaterial subsidiaries). Pursuant to the Intercreditor Agreement, the holders of the 8.75% Notes and the WCC Term Loan Facility have a subordinate lien on these assets. The Revolver has a maturity date of December 31, 2018. The Company capitalized debt issuance costs of $0.7 million in 2014 related to the Revolver amendments.
Borrowings under the Revolver initially bear interest either at a rate 0.75% in excess of the base rate (as detailed in the Second Amended and Restated Loan Agreement) or at a rate 2.75% per annum in excess of LIBOR, at the Borrowers’ election. An unused line fee of 0.50% per annum is payable monthly on the average unused amount of the revolver.
The loan agreement contains various affirmative, negative and financial covenants. Financial covenants in the agreement include certain fixed charge coverage ratios. The fixed charge coverage ratios must meet or exceed certain specified minimums. The Company met these covenant requirements as of December 31, 2015.
Capital Leases
The Company engages in leasing transactions for equipment utilized in its mining operations. At December 31, 2015 and 2014, the capital leases outstanding had a weighted average interest rate of 4.51% and 4.66%, respectively, and mature at various dates beginning in 2016 through 2020. During the year ended December 31, 2015, the Company entered into $15.2 million of new capital leases.
9. POSTRETIREMENT MEDICAL BENEFITS
The Company provides postretirement medical benefits to retired employees and their dependents, mandated by the Coal Industry Retiree Health Act of 1992 and pursuant to collective bargaining agreements. The Company also provides these benefits to qualified full-time employees pursuant to collective bargaining agreements. These benefits are provided through self-insured programs.
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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONT.)
The following table sets forth the actuarial present value of postretirement medical benefit obligations and amounts recognized in the Company’s financial statements:
The Company has elected to amortize its transition obligations over a 20-year period. Prior service costs and credits and actuarial gains and losses are amortized over the average life expectancy or average future service of the plan’s participants. The following amounts will be amortized from accumulated other comprehensive loss into net periodic benefit cost in 2016 (in millions):
The components of net periodic postretirement medical benefit cost are as follows:
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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONT.)
The following table shows the net periodic postretirement medical benefit costs that relate to current and former mining operations:
The costs for the former mining operations are included in Heritage health benefit expenses and the costs for current operations are included as operating expenses.
Assumptions
The weighted-average assumptions used to determine the benefit obligations as of the end of each year were as follows:
The discount rate is adjusted annually based on an Aa corporate bond index adjusted for the difference in the duration of the bond index and the duration of the benefit obligations. This rate is calculated using a yield curve, which is developed using the average yield for bonds in the tenth to ninetieth percentiles, which excludes bonds with outlier yields.
The weighted-average assumptions used to determine net periodic benefit cost were as follows:
The following presents information about the assumed health care trend rate:
The effect of a one percent change on the health care cost trend rate used to calculate periodic postretirement medical benefit costs and the related benefit obligation are summarized in the table below:
Cash Flows
The following benefit payments and Medicare D subsidy (which the Company receives as a benefit partially offsetting its prescription drug costs for retirees and their dependents) are expected by the Company:
WESTMORELAND COAL COMPANY AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONT.)
Combined Benefit Fund
Additionally, the Company makes payments to the UMWA Combined Benefit Fund, or CBF, which is a multiemployer health plan neither controlled by nor administered by the Company. The CBF is designed to pay health care benefits to UMWA workers (and dependents) who retired prior to 1976. The Company is required by the Coal Act to make monthly premium payments into the CBF. These payments are based on the number of the Company’s UMWA employees who retired prior to 1976, and the Company’s pro-rata assigned share of UMWA retirees whose companies are no longer in business. Contributions to the CBF have decreased over the past three years due to a declining population. The Company expenses payments to the CBF when they are due. The following payments were made to the CBF (in millions):
Workers’ Compensation Benefits
The Company was self-insured for workers’ compensation benefits prior to January 1, 1996. Since 1996, the Company has purchased third-party insurance for workers’ compensation claims.
The following table shows the changes in the Company’s workers’ compensation obligation:
The discount rates used in determining the workers’ compensation benefit accruals are adjusted annually based on ten-year Treasury bond rates. At December 31, 2015 and 2014, the rates were 2.2% and 2.0%, respectively.
Black Lung Benefits
The Company is self-insured for federal and state black lung benefits for former heritage employees and has established an independent trust to pay these benefits.
The following table sets forth the funded status of the Company’s black lung obligation:
WESTMORELAND COAL COMPANY AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONT.)
The discount rates used in determining the actuarial present value of the black lung benefit obligation are based on corporate bond yields and are adjusted annually. At December 31, 2015 and 2014, the rates used were 3.95% and 3.40%, respectively.
Plan Assets
The Company's trust assets include cash and cash equivalents and U.S treasury securities, and are all valued at level 1 in the fair value hierarchy (refer to Note 14 - Fair Value Measurements). The fair value of all trust assets is determined based on quoted prices in active markets. The fair value of the Company’s Black Lung trust assets by asset category is as follows:
10. PENSION AND OTHER SAVING PLANS
Defined Benefit Pension Plans
The Company provides defined benefit pension plans to qualified full-time employees pursuant to collective bargaining agreements. Benefits are generally based on years of service and the employee’s average annual compensation for the highest five continuous years of employment as specified in the plan agreement. The Company’s funding policy is to contribute annually the minimum amount prescribed, as specified by applicable regulations. The Company may make additional discretionary contributions. In 2009, the Company froze its pension plan for non-represented employees.
Supplemental Executive Retirement Plan
The Company maintains a Supplemental Executive Retirement Plan or SERP for former executives as a result of employment or severance agreements. The SERP is an unfunded non-qualified deferred compensation plan, which provides benefits to certain employees beyond the maximum limits imposed by the Employee Retirement Income Security Act and the Internal Revenue Code. The Company does not expect to add new participants to its SERP plan.
WESTMORELAND COAL COMPANY AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONT.)
The following table provides a reconciliation of the changes in the benefit obligations of the plans and the fair value of assets of the qualified plans and the amounts recognized in the Company’s financial statements for both the defined benefit pension and SERP plans:
Prior service costs and actuarial gains and losses are amortized over the expected future period of service of the plan’s participants. The following amounts will be amortized from accumulated other comprehensive loss into net periodic benefit cost in 2016 (in millions):
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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONT.)
The components of net periodic benefit cost are as follows:
These costs are included in the accompanying statements of operations in Cost of sales and Selling and administrative expenses.
In certain of the Company's pension plans, lump sum distributions during 2014 exceeded the sum of those plans' service and interest costs. As a result, the Company recorded a $3.7 million loss on settlement accounting in 2014. In addition, the Company recorded a $0.9 million loss on curtailment accounting due to the expectation that the future service of present employees at the Beulah Mine will be significantly reduced in the future. These costs are included in the accompanying statements of operations in Selling and administrative expenses.
Assumptions
The weighted-average assumptions used to determine the benefit obligations as of the end of each year were as follows:
The discount rate is adjusted annually based on an Aa corporate bond index adjusted for the difference in the duration of the bond index and the duration of the benefit obligations. This rate is calculated using a yield curve, which is developed using the average yield for bonds in the tenth to ninetieth percentiles, which excludes bonds with outlier yields.
The following table provides the assumptions used to determine net periodic benefit cost:
The Company establishes the expected long-term rate of return at the beginning of each fiscal year based upon historical returns and projected returns on the underlying mix of invested assets. The Company utilizes modern portfolio theory modeling techniques in the development of its return assumptions. This technique projects rates of return that can be generated through various asset allocations that lie within the risk tolerance set forth by the Company. The risk assessment provides a link
WESTMORELAND COAL COMPANY AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONT.)
between a pension plan's risk capacity, management's willingness to accept investment risk and the asset allocation process, which ultimately leads to the return generated by the invested assets.
Plan Assets
The Company’s investment goals are to maximize returns subject to specific risk management policies. The Company sets the expected return on plan assets based on historical trends and forecasts provided by its third-party fund managers. Its risk management policies permit investments in mutual funds, and prohibit direct investments in debt and equity securities and derivative financial instruments. The Company addresses diversification by the use of mutual fund investments whose underlying investments are in fixed income and equity securities, both domestic and international. These mutual funds are readily marketable and can be sold to fund benefit payment obligations as they become payable.
The weighted-average target asset allocation of the Company’s pension trusts were as follows at December 31, 2015:
The fair value of the Company’s pension plan assets by asset category is as follows:
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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONT.)
(a) Large-cap blend funds seek to provide long-term growth of capital. They seek to provide investment results that approximate the performance of the Standard & Poor’s Composite 1500 Index.
(b) International blends seek to have a diversified portfolio of investments, invading fixed-income and equity-focused investments in international markets.
(c) Fixed income domestic funds seek to invest in high-quality corporate bonds with over 15 years to maturity.
(d) Fixed income long term bond funds seek to achieve performance results similar to the Barclays Capital U.S. Aggregate Bond Index. This fund invests primarily in corporate and government bonds.
(e) The stable value fund seeks to invest in publicly traded and privately placed debt securities and mortgage loans, and to a lesser extent, real estate and other equity investments in order to provide a guaranteed rate of return.
The Company’s Level 1 assets include securities held by registered investment companies and its common stock, which are both typically valued using quoted market prices of an active market. Cash and cash equivalents and short-term investments are predominantly held in money market accounts.
The Company’s Level 2 assets include pooled separate accounts, which are valued based on the quoted market prices of the securities underlying the investments.
The Company’s Level 3 assets include interest in limited partnerships and limited liability companies that invest in privately held companies or privately held real estate assets. These assets are valued by the respective partnership or company manager using market and income approaches. The market approach consists of using comparable market transactions or values. The income approach consists of the net present value of estimated future cash flows, adjusted as appropriate for liquidity, credit, market and other risk factors. The inputs considered in the valuations include original transaction prices, recent transactions in the same or similar instruments, changes in financial ratios or cash flows, discounted cash flow valuations, and general economic and market conditions.
Contributions
The Company contributed $3.7 million in cash to its retirement plans during 2015. In 2016, the Company expects to make approximately $0.5 million of pension plan contributions.
Cash Flows
The following benefit payments are expected to be paid from its pension plan assets:
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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONT.)
The benefits expected to be paid are based on the same assumptions used to measure the Company’s pension benefit obligation at December 31, 2015 and include estimated future employee service.
Multi-Employer Pension
The Company contributes to the Central Pension Fund, or the Plan, a multiemployer defined benefit pension plan for its WECO, WRI and WSC entities pursuant to collective bargaining agreements. The Plan’s Employer Identification Number is 36-6052390. These employers contribute to the Plan based on a negotiated rate per hour worked per participating employee. For the Plan’s year-end dates of January 31, 2015 and 2014, no single employer contributed more than 5% of total contributions to the Plan. As of the Plan’s year-end date January 31, 2015, it had a healthy or greater than 80% funding status.
The following table shows required information for each employer contributing to the Central Pension Fund:
Other Plans
The Company sponsors 401(k) saving plans for U.S. employees and provides contributions to employee savings plans at its Canadian operation to assist employees in providing for their future retirement needs. The Company’s expense was $10.8 million, $8.5 million and $3.6 million for the years ended December 31, 2015, 2014 and 2013, respectively. During 2015, the Company’s expense of $10.8 million consisted of $7.1 million in cash contributions and $3.7 million in contributions of Company stock to the plans. During 2014, the Company’s expense of $8.5 million consisted of $6.7 million in cash contributions and $1.8 million in contributions of Company stock to the plans. During 2013, the Company’s expense of $3.6 million consisted of $1.2 million in cash contributions and $2.4 million in contributions of Company stock to the plans.
11. HERITAGE HEALTH BENEFIT EXPENSES
The caption Heritage health benefit expenses used in the consolidated statements of operations refers to costs of benefits the Company provides to its former mining operation employees. The components of these expenses are as follows:
WESTMORELAND COAL COMPANY AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONT.)
12. ASSET RETIREMENT OBLIGATIONS, CONTRACTUAL THIRD-PARTY RECLAMATION RECEIVABLE, AND RECLAMATION DEPOSITS
The asset retirement obligations (“ARO”), contractual third-party reclamation receivables, and reclamation deposits at December 31, 2015 are summarized below:
Asset Retirement Obligations
Changes in the Company’s asset retirement obligations were as follows:
The Company or its subsidiaries are responsible for the total amount of final reclamation costs for its mines and ROVA. The financial responsibility for a portion of final reclamation of the mines when they are closed has been transferred by contract to certain customers, while other customers have provided guarantees or funded escrow accounts to cover final reclamation costs. Costs of reclamation of mining pits prior to mine closure are recovered in the price of coal shipped.
As of December 31, 2015, the Company had $384.1 million in surety bonds outstanding and $103.2 million in letters of credit to secure reclamation obligations.
Contractual Third-Party Reclamation Receivables
The Company has recognized as an asset of $94.9 million as contractual third-party reclamation receivables, representing the present value of customer obligations to reimburse the Company for reclamation expenditures.
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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONT.)
Reclamation Deposits
The Company’s reclamation deposits will be used to fund final reclamation activities. The carrying value (which equals estimated fair value) of reclamation deposits at December 31, 2015 are as follows:
In both 2015 and 2014, the Company recorded a gain of less than $0.1 million on the sale of available-for-sale securities held as reclamation deposits. The cost basis of an investment sold is specifically identified.
Available-for-Sale Reclamation Deposits
The cost basis, gross unrealized holding gains and fair value of available-for-sale securities are as follows:
Maturities of available-for-sale securities are as follows at December 31, 2015:
13. DERIVATIVE INSTRUMENTS
Derivative Liabilities
The Company evaluates all of its financial instruments to determine if such instruments are derivatives, derivatives that qualify for the normal purchase normal sale exception, or contain features that qualify as embedded derivatives. All derivative financial instruments, except for derivatives that qualify for the normal purchase normal sale exception, are recognized on the balance sheet at fair value. Changes in fair value are recognized in earnings if they are not eligible for hedge accounting or in other comprehensive income if they qualify for cash flow hedge accounting.
In the first quarter of 2014, the Company entered into two foreign currency exchange forward contracts to purchase Canadian Dollars to manage a portion of its exposure to fluctuating rates of exchange on anticipated Canadian Dollar-denominated Canadian Acquisition cash flows. These two foreign currency contracts had a total notional amount of $348.3 million and were settled in April 2014.
During 2014, the Company entered into contracts to purchase power at its ROVA facility to manage exposure to power price fluctuations. These contracts cover the period from April 2014 to March 2019. Over the remaining contract lives, contracted power prices range from $41.05 to $55.20 per megawatt hour with a weighted average price of $43.93. The fair value of these power price derivatives are based on comparing contracted prices to projected future prices.
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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONT.)
The fair value of outstanding derivative instruments not designated as hedging instruments on the accompanying Consolidated Balance Sheets was as follows (in thousands):
The effect of derivative instruments not designated as hedging instruments on the accompanying Consolidated Statements of Operations was as follows (in thousands):
14. FAIR VALUE MEASUREMENTS
Fair value is the price that would be received to sell an asset or paid to transfer a liability in an orderly transaction between market participants at the measurement date. The Company is required to disclose the fair value of financial instruments where practicable. The carrying amounts of cash equivalents, accounts receivable and accounts payable reflected on the consolidated balance sheets approximate the fair value of these instruments due to the short duration to their maturities. Long-term debt fair value estimates are based on observed prices for securities with an active trading market when available (Level 2) and otherwise using discount rate estimates based on interest rates as of December 31, 2015 (Level 3).
The estimated fair value of the Company’s debt with fixed and variable interest rates are as follows:
The table below sets forth, by level, the Company’s financial assets and liabilities that are accounted for at fair value on a recurring basis:
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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONT.)
15. RESTRICTED STOCK UNITS, STOCK OPTIONS, AND STOCK APPRECIATION RIGHTS (SARs)
As of December 31, 2015, the Company had restricted stock units, stock options, and stock-settled stock appreciation rights, or SARs, outstanding from three stock incentive plans. Two of these plans were terminated in October 2009. The Company grants employees and non-employee directors restricted stock units from the Amended and Restated 2007 and 2014 Equity Incentive Stock Plans. The Company grants employees and non-employee directors restricted stock units. Non-employee directors receive equity awards with a value of $90,000 after each annual meeting.
The maximum number of remaining shares that can be issued under the 2007 Incentive Stock Plan is 296,431. The maximum number of remaining shares that can be issued under the 2014 Incentive Stock Plan is 526,460.
Compensation cost arising from share-based arrangements is shown in the following table:
Restricted Stock Units
The Company may issue restricted stock units, which requires no payment from the employee. Restricted stock units typically vest ratably over three years. Upon vesting, the Company can elect to settle the restricted stock units in either cash or the Company’s common stock. Compensation expense is based on the fair value on the grant date and is recorded ratably over the vesting period.
In April 2015, the Company granted 233,974 restricted stock units, of which 117,003 units will vest ratably over a three-year period. The remaining 116,971 units are performance based, which will vest and pay out at the end of a three-year period if performance goals are met. The Company’s management believes it is probable that the target performance condition will be met.
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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONT.)
A summary of restricted stock award activity for the year ended December 31, 2015 is as follows:
____________________
(1)
Expected to be recognized over the next three years.
Additional information related to restricted stock units:
Stock Options
Stock options generally vest over three years, expire ten years from the date of grant, and have an option price equal to the market value of the stock on the date of grant.
Information with respect to stock option activity for the year ended December 31, 2015, is as follows:
Additional information related to stock options:
There were no stock options granted during 2015, 2014 or 2013.
SARs
SARs generally vest over three years, expire ten years from the date of grant, and have a base price equal to the market value of the stock on the date of grant. Upon vesting, the holders may exercise the SARs and receive a number of shares of common stock having a value equal to the appreciation in the value of the common stock between the grant date and the exercise date.
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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONT.)
Information with respect to SARs granted and outstanding for the year ended December 31, 2015 is as follows:
Additional information related to SARs:
There were no SARs granted or vested during 2015, 2014, or 2013.
16. STOCKHOLDERS’ EQUITY AND ACCUMULATED OTHER COMPREHENSIVE INCOME (LOSS)
Noncontrolling Interest
On acquisition of WMLP we recorded a noncontrolling interest totaling $15.3 million, which represents the equity attributable to the noncontrolling unitholders, who owned approximately 21% of the outstanding Common Units of WMLP at December 31, 2014. The Kemmerer Drop resulted in our acquisition of an additional 15% interest in WMLP (on a fully diluted basis) with a corresponding decrease in noncontrolling interest ownership. Activity in the noncontrolling interest is summarized as follows (in millions):
Preferred and Common Stock
The Company has one class of capital stock outstanding at December 31, 2015, common stock, par value $0.01 per share. During the first quarter of 2015, all of the Company’s Series A Convertible Exchangeable Preferred Stock were converted or redeemed, consisting of 88,494 shares of preferred stock being converted into 604,557 shares of common stock and 3,175 shares of preferred stock were redeemed under a mandatory redemption for $0.3 million. The Company paid less than $0.1 million of preferred stock dividends for the year ended December 31, 2015.
WESTMORELAND COAL COMPANY AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONT.)
Accumulated Other Comprehensive Income (Loss)
The following is a summary of accumulated other comprehensive income (loss):
Changes in Accumulated Other Comprehensive Loss
The following table reflects the changes in accumulated other comprehensive loss by component:
The following table reflects the reclassifications out of accumulated other comprehensive loss for the year ended December 31, 2015 (in thousands):
WESTMORELAND COAL COMPANY AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONT.)
____________________
(1)
Amounts in parentheses indicate debits to income/loss.
(2)
These accumulated other comprehensive income components are included in the computation of net periodic pension cost. (See Note 10 - Pension And Other Saving Plans for additional details)
(3)
These accumulated other comprehensive income components are included in the computation of net periodic postretirement medical cost. (See Note 9 - Postretirement Medical Benefits for additional details)
Restricted Net Assets
WCC has obligations to pay pension and postretirement medical benefits, to fund corporate expenditures, and to pay interest on the 8.75% Notes and the WCC Term Loan Facility. However, WCC conducts no operations, has no source of revenue and is fully dependent on distributions from its subsidiaries to pay its costs. Due to the Master Limited Partnership structure and the WMLP Term Loan Facility, at December 31, 2015, WMLP is limited in its ability to distribute funds to WCC. The amount of cash WMLP can distribute on its units principally depends upon the amount of cash it generates from its operations, which will fluctuate from quarter to quarter. The WMLP Term Loan Facility contains customary financial and other covenants and it permits distributions to its unitholders under specified circumstances. Borrowings under the WMLP Term Loan Facility are secured by substantially all of its physical assets.
At December 31, 2015, WMLP had approximately $13.2 million of net assets that were not available to be transferred to WCC in the form of dividends, loans, or advances due to restrictions on the Master Limited Partnership as mentioned above.
Equity Offering
On July 16, 2014, the Company completed a public offering of 1,684,507 shares of common stock at $35.50 per share for gross proceeds of $59.8 million. Brokerage fees were $1.775 per share or $3.0 million and legal and other fees associated with the offering were $0.3 million.
WESTMORELAND COAL COMPANY AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONT.)
17. INCOME TAX
The Company is subject to U.S. and Canadian income tax as well as tax in multiple state jurisdictions. The tax years 2000 through 2015 remain open to examination for U.S. federal income tax matters. The Company’s income (loss) before income taxes is as follows:
Income tax expense (benefit) reflected in the consolidated statement of operations consisted of:
The effective tax rate differs from the U.S. federal statutory rate as follows:
The $132.3 million increase in valuation allowance for the year ended December 31, 2015 is due to the tax effect of the change in current year temporary items, credits, net operating losses, and postretirement medical benefit and pension obligations. During 2015 the Company completed an amalgamation of two of our Canadian subsidiaries as part of a tax planning strategy. The amalgamation resulted in a decrease in the Company’s Canadian net deferred tax asset, necessitating the $32.6 million release of a portion of the Company’s valuation allowance. The $13.2 million Kemmerer deferred tax asset
WESTMORELAND COAL COMPANY AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONT.)
removal for the year ended December 31, 2015 is due to the Company dropping the Kemmerer mine and assets into the Company’s master limited partnership, Westmoreland Resource Partners, LP on August 1, 2015.
The tax effects of temporary differences that give rise to the deferred tax assets and deferred tax liabilities are presented below:
As of December 31, 2015, the Company had significant deferred tax assets. The deferred tax assets include U.S. federal, state regular and foreign NOLs, AMT credit carryforwards, ICTC carryforwards, and net deductible reversing temporary differences related to on-going differences between book and taxable income. The Company determined that since its net deductible temporary differences will not reverse for the foreseeable future, and it is unable to forecast regular taxable income when they do reverse, a full valuation allowance is required for these deferred tax assets. The net valuation allowance increased by $91.7 million and $141.7 million during the years ended December 31, 2015 and December 31, 2014 respectively.
As of December 31, 2015, the Company has available U.S. federal net operating loss carryforwards to reduce future regular taxable income of $417.3 million, expiring between 2018 and 2035. The Company has ICTC carryforwards of $54.5 million available to reduce future income taxes, which expire between 2026 and 2035.
Currently the Company has an excess tax over book basis in its investment in Canadian subsidiaries and the Company does not expect this deferred tax asset to reverse in the foreseeable future. Accordingly, there has been no recognition of any deferred tax asset on the outside basis of investments in subsidiaries, in accordance with ASC 740.
WESTMORELAND COAL COMPANY AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONT.)
Foreign Income Taxes
As of December 31, 2015, the Company has available foreign net operating loss carryforwards to reduce future regular taxable income of approximately $92.9 million expiring in years 2031 through 2035.
Uncertain tax positions
The Company recorded $4.0 million and zero in uncertain tax positions for the year ended December 31, 2015 and December 31, 2014, respectively. The Company recognizes interest and penalties related to income tax matters in income tax expense, for which none was recorded for the years ended December 31, 2015, 2014 or 2013. No uncertain tax positions are expected to change in the next 12 months.
18. COMMITMENTS AND CONTINGENCIES
Leases and other Commitments
The following shows the gross value and accumulated amortization of property, plant and equipment and mine development assets under capital leases related primarily to the leasing of mining equipment as of December 31:
Future minimum capital and operating lease payments as of December 31, 2015, are as follows:
Rental expense under operating leases during the years ended December 31, 2015, 2014 and 2013 totaled $25.2 million, $16.6 million and $11.8 million, respectively.
The Company leases certain of its coal reserves from third parties and pays royalties based on either a per ton rate or as a percentage of revenues received. Royalties charged to expense under all such lease agreements amounted to $96.7 million, $61.8 million and $43.6 million in the years ended December 31, 2015, 2014 and 2013, respectively.
At December 31, 2015, the Company had fuel supply contracts outstanding with a minimum purchase requirement of 3.9 million gallons of diesel fuel per year. These contracts qualify for the normal purchase normal sale exception under hedge accounting.
Contingencies
The Company is a party to various claims and lawsuits with respect to various matters. The Company provides for costs related to contingencies when a loss is probable and the amount is reasonably estimable. After conferring with counsel, it is the opinion of management that the ultimate resolution of pending claims will not have a material adverse effect on the consolidated financial condition, results of operations, or liquidity of the Company.
WESTMORELAND COAL COMPANY AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONT.)
As part of the Canadian Acquisition in 2014, the Company became responsible for remediation work for a breach on a containment pond at a currently inactive mine that occurred on October 31, 2013. The prior owner, Sherritt International Corporation, has indemnified Westmoreland against past and future liability stemming from the incident. As of December 31, 2015, the Company has recorded $8.1 million in Other current liabilities for the estimated costs of remediation work and a corresponding amount in current receivables Other to reflect the indemnification by the prior owner.
19. BUSINESS SEGMENT INFORMATION
Segment information is based on a management approach, which requires segmentation based upon the Company’s internal organization, reporting of revenue, and operating income.
The Company’s operations are classified into six reporting segments: Coal - U.S., Coal - Canada, Coal - WMLP, Power, Heritage, and Corporate. The Coal - U.S. reporting segment includes the operations of coal mines located in Montana, North Dakota, Ohio and Texas. The Coal - Canada reporting segment includes the operations of coal mines located in Alberta and Saskatchewan. The Coal - WMLP reporting segment includes the operations of Westmoreland Resource Partners, LP, a publicly-traded coal master limited partnership. The Kemmerer Drop was completed on August 1, 2015 and, accordingly, to enable comparability, all segment disclosures have been adjusted to remove financial information for Kemmerer from the Coal - U.S. segment and present it in the Coal - WMLP segment for all periods presented. The Power segment includes its ROVA operations located in North Carolina. The Heritage segment costs primarily include benefits the Company provides to former mining operation employees as well as other administrative costs associated with providing those benefits and cost containment efforts. The Corporate segment primarily consists of corporate administrative expenses and includes eliminations for intersegment revenues and cost of sales.
Summarized financial information by segment is as follows:
____________________
WESTMORELAND COAL COMPANY AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONT.)
(1)
The Buckingham Acquisition was completed on January 1, 2015. For the year ended December 31, 2015, revenues for Buckingham were $80.4 million and operating losses were $3.2 million.
(2)
Financial information of the Kemmerer mine for the year ended December 31, 2014 and 2013 was previously presented under the Coal - U.S. segment and is now presented under the Coal - WMLP segment for all periods presented due to the Kemmerer Drop that occurred on August 1, 2015.
(3)
The Canadian operations were acquired on April 28, 2014, therefore, information for the year ended December 31, 2014 includes approximately eight months of operations and there is no activity for 2013.
(4)
The Ohio operations reported under the segment Coal - WMLP were acquired on December 31, 2014. For the year ended December 31, 2015, revenues for the Ohio operations were $225.2 million and operating losses were $26.8 million.
(5)
The Coal - WMLP segment recorded revenues of $30.9 million for intersegment revenues to the Coal - U.S. segment for the year ended December 31, 2015.
(6)
Operating income (loss) for the Power segment for 2015 includes an impairment charge of $133.1 million.
(7)
Eliminations for intersegment revenues and cost of sales are presented within the Corporate segment.
A reconciliation of segment operating income (loss) to loss before income taxes follows:
The Company derives its revenues from a few key customers. The customers from which more than 10% of total revenue has been derived and the percentage of total revenue from those customers is summarized as follows:
____________________
(1)
The revenue from Customers D, E, F, and G did not exceed 10% in 2015 and 2014.
WESTMORELAND COAL COMPANY AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONT.)
20. QUARTERLY FINANCIAL DATA (UNAUDITED)
Summarized quarterly financial data is as follows:
____________________
(1)
Operating income (loss) for the three months ended December 31, 2015 includes $136.2 million of impairment charges at ROVA and the Coal Valley mine in the Coal - Canada segment.
The Canadian Acquisition was completed on April 28, 2014; therefore, operating results includes activities of the Canadian operations beginning with the three months ended June 30, 2014.
The WMLP Transactions were completed December 31, 2014; therefore, operating results includes activities of the Ohio operations beginning with the three months ended March 31, 2015. Additionally, the Buckingham Acquisition was completed January 1, 2015; therefore, operating results includes activities of the Buckingham operations beginning with the three months ended March 31, 2015.
21. SUBSEQUENT EVENTS
Acquisition of San Juan
On January 31, 2016, Westmoreland San Juan, LLC (“WSJ”), a special purpose subsidiary of Westmoreland, acquired San Juan Coal Company (“SJCC”), which operates the San Juan mine in Farmington, New Mexico, and San Juan Transportation Company (together with SJCC, the “San Juan Entities” and such transaction, the “Acquisition”) for a total cash purchase price of approximately $127 million, subject to post-closing adjustments. The San Juan mine is the exclusive supplier of coal to the adjacent San Juan Generating Station (“SJGS”) under a coal supply agreement with tonnage and pricing adjusting quarterly through 2022.
WSJ financed the Acquisition with a $125 million loan from NM Capital Utility Corporation, an affiliate of Public Service Company of New Mexico (one of the owners of SJGS), and with available cash on hand. The loan is structured as a senior secured term loan (the “Loan”) maturing February 1, 2021 and is expected to bear interest at a (i) 7.25% rate (the “Margin Rate”) plus (ii) (A) the London Interbank Offered Rate for a three month period plus (B) a statutory reserve rate, which such Margin Rate increases incrementally during each year of the Loan term. The Loan has no prepayment penalties. The agreements governing the Loan include representations and warranties and covenants regarding the ownership and operation of SJCC and the properties acquired in the Acquisition and standard special purpose bankruptcy remote entity covenants designed to preserve the separateness from Westmoreland of each of (i) WSJ, (ii) its direct parent company, Westmoreland San Juan Holdings, Inc., and (iii) SJCC (collectively, the “Westmoreland San Juan Entities”). Obligations under the Loan are recourse only to the Westmoreland San Juan Entities and their assets and neither Westmoreland nor its subsidiaries (other than the Westmoreland San Juan Entities) is an obligor under the Loan in any respect. The agreement governing the Loan requires that all revenues of the San Juan Entities, aside from payments on certain leases, are deposited into a cash management collection account swept monthly for operating expenses, capital expenditures, and Loan payment and prepayment.
ITEM 9
ITEM 9
- CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE.
None.
ITEM 9A
ITEM 9A
- CONTROLS AND PROCEDURES.
Evaluation of Disclosure Controls and Procedures
Our disclosure controls and procedures are designed to, among other things, provide reasonable assurance that material information, both financial and non-financial, and other information required under the securities laws to be disclosed is accumulated and communicated to senior management, including the principal executive officer and principal financial officer, on a timely basis. As of December 31, 2015, the end of the period covered by this Annual Report on Form 10-K, we carried out an evaluation of the effectiveness of the design and operation of our disclosure controls and procedures. Based upon that evaluation, our Chief Executive Officer and Chief Financial Officer have evaluated our disclosure controls and procedures (as defined in Rules 13a-15(e) and 15d-15(e) under the Securities Exchange Act of 1934) as of December 31, 2015, and concluded that such controls and procedures are effective to provide reasonable assurance that the desired control objectives were achieved.
Changes in Internal Control Over Financial Reporting
We periodically review our internal control over financial reporting as part of our efforts to ensure compliance with the requirements of Section 404 of the Sarbanes-Oxley Act of 2002. In addition, we routinely review our system of internal control over financial reporting to identify potential changes to our processes and systems that may improve controls and increase efficiency, while ensuring that we maintain an effective internal control environment. Changes may include such activities as implementing new systems, consolidating the activities of acquired business units, migrating certain processes to our shared services organizations, formalizing and refining policies and procedures, improving segregation of duties and adding monitoring controls. In addition, when we acquire new businesses, we incorporate our controls and procedures into the acquired business as part of our integration activities. There have been no changes in our internal control over financial reporting that occurred during the three months ended December 31, 2015 that have materially affected, or are reasonably likely to materially affect, our internal control over financial reporting.
Management's Report on Internal Control Over Financial Reporting
Management is responsible for maintaining and establishing adequate internal control over financial reporting. Our internal control framework and processes are designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of our consolidated financial statements for external purposes in accordance with U.S. generally accepted accounting principles. Because of inherent limitations, any system of internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate. Management conducted an assessment of the effectiveness of our internal control over financial reporting using the criteria set by the Committee of Sponsoring Organizations of the Treadway Commission (COSO) in Internal Control - Integrated Framework (2013). Based on this assessment, management concluded that the Company's internal control over financial reporting was effective to provide reasonable assurance that the desired control objectives were achieved as of December 31, 2015. Our Independent Registered Public Accounting Firm, Ernst & Young LLP, has audited our internal control over financial reporting, as stated in their unqualified opinion report included herein.
Report of Independent Registered Public Accounting Firm
The Board of Directors and Shareholders of Westmoreland Coal Company and subsidiaries
We have audited Westmoreland Coal Company and subsidiaries’ internal control over financial reporting as of December 31, 2015, based on criteria established in Internal Control-Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (2013 framework) (the COSO criteria). Westmoreland Coal Company and subsidiaries’ management is responsible for maintaining effective internal control over financial reporting, and for its assessment of the effectiveness of internal control over financial reporting included in the accompanying Management’s Report on Internal Control over Financial Reporting. Our responsibility is to express an opinion on the company’s internal control over financial reporting based on our audit.
We conducted our audit in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether effective internal control over financial reporting was maintained in all material respects. Our audit included obtaining an understanding
of internal control over financial reporting, assessing the risk that a material weakness exists, testing and evaluating the design and operating effectiveness of internal control based on the assessed risk, and performing such other procedures as we considered necessary in the circumstances. We believe that our audit provides a reasonable basis for our opinion.
A company’s internal control over financial reporting is a process designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles. A company’s internal control over financial reporting includes those policies and procedures that (1) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the company; (2) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and that receipts and expenditures of the company are being made only in accordance with authorizations of management and directors of the company; and (3) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use, or disposition of the company’s assets that could have a material effect on the financial statements.
Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.
In our opinion, Westmoreland Coal Company and subsidiaries maintained, in all material respects, effective internal control over financial reporting as of December 31, 2015, based on the COSO criteria.
We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), the consolidated balance sheets of Westmoreland Coal Company and subsidiaries’ as of December 31, 2015 and 2014 and the related consolidated statements of operations, comprehensive income (loss), shareholders’ deficit, and cash flows for each of the three years in the period ended December 31, 2015, and our report dated March 11, 2016 expressed an unqualified opinion thereon.
/s/ ERNST & YOUNG LLP
Denver, Colorado
March 11, 2016
Evaluation of Disclosure Controls and Procedures
As of December 31, 2015, management conducted an evaluation, under the supervision and with the participation of our CEO and CFO, of the effectiveness of the design and operation of our disclosure controls and procedures, as such term is defined in Rule 13a-15(e) and 15d-15(e) of the Exchange Act. Based upon that evaluation, our CEO and CFO concluded that our disclosure controls and procedures were effective as December 31, 2015 in ensuring that information required to be disclosed was recorded, processed, summarized and reported within the time periods specified in the SEC’s rules and forms, and that information required to be disclosed by us in such reports is accumulated and communicated to management, including our CEO and CFO, as appropriate, to allow timely decisions regarding required disclosure.
PART III
ITEM 10
ITEM 10
- DIRECTORS, EXECUTIVE OFFICERS AND CORPORATE GOVERNANCE.
The information required by Item 10 will be included under the headings Directors, Executive Officer, Corporate Governance and Section 16(a) Beneficial Ownership Reporting Compliance in our definitive proxy statement for our Annual Meeting of Stockholders to be held May 17, 2016, and such required information is incorporated herein by reference.
ITEM 11
ITEM 11
- EXECUTIVE COMPENSATION.
The information required by Item 11 will be included under the headings Corporate Governance, Director Compensation for 2015, Compensation Discussion and Analysis and Executive Compensation for 2015 in our definitive proxy statement for our Annual Meeting of Stockholders to be held May 17, 2016, and such required information is incorporated herein by reference.
ITEM 12
ITEM 12
- SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT AND RELATED STOCKHOLDER MATTERS.
The information required by Item 12 will be included under the headings Beneficial Ownership of Securities and Equity Compensation Plan Information in our definitive proxy statement for our Annual Meeting of Stockholders to be held May 17, 2016, and such required information is incorporated herein by reference.
ITEM 13
ITEM 13
- CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS, AND DIRECTOR INDEPENDENCE.
The information required by Item 13 will be included under the headings Certain Transactions and Corporate Governance in our definitive proxy statement for our Annual Meeting of Stockholders to be held May 17, 2016, and such required information is incorporated herein by reference.
ITEM 14
ITEM 14
- PRINCIPAL ACCOUNTANT FEES AND SERVICES.
The information required by Item 14 will be included under the heading Auditors in our definitive proxy statement for our Annual Meeting of Stockholders to be held May 17, 2016, and such required information is incorporated herein by reference.
PART IV
ITEM 15
ITEM 15 -EXHIBITS AND FINANCIAL STATEMENT SCHEDULES.
1. The following consolidated financial statements for Westmoreland Coal Company are filed herewith in Item 8:
Report of Independent Registered Public Accounting Firm
Consolidated Balance Sheets
Consolidated Statements of Operations
Consolidated Statements of Comprehensive Income (Loss)
Consolidated Statements of Shareholders’ Deficit
Consolidated Statements of Cash Flows
Notes to Consolidated Financial Statements
2. The following financial statement schedules are filed herewith:
Schedule I - Condensed Financial Statements of Parent Company
3. The exhibits listed in the Exhibit Index are filed with or incorporated by reference in this Annual Report on Form 10-K.
SIGNATURES
Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized.
WESTMORELAND COAL COMPANY
Date:
March 11, 2016
Signature: /s/ Kevin A. Paprzycki
Name: Kevin A. Paprzycki
Title: Chief Executive Officer
(A Duly Authorized Officer)
Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below by the following persons on behalf of the registrant and in the capacities and on the dates indicated.
WESTMORELAND COAL COMPANY
SCHEDULE I - CONDENSED BALANCE SHEETS
(Parent Company Information - See Notes to Consolidated Financial Statements)
WESTMORELAND COAL COMPANY
SCHEDULE I - CONDENSED BALANCE SHEETS
(Parent Company Information - See Notes to Consolidated Financial Statements)
WESTMORELAND COAL COMPANY
SCHEDULE I - CONDENSED STATEMENTS OF OPERATIONS
(Parent Company Information - See Notes to Consolidated Financial Statements)
WESTMORELAND COAL COMPANY
SCHEDULE I - COMPREHENSIVE INCOME (LOSS)
(Parent Company Information - See Notes to Consolidated Financial Statements)
WESTMORELAND COAL COMPANY
SCHEDULE I - CONDENSED STATEMENTS OF CASH FLOWS
(Parent Company Information - See Notes to Consolidated Financial Statements)
WESTMORELAND COAL COMPANY
SCHEDULE I - NOTES TO FINANCIAL STATEMENTS
(Parent Company Information - See Notes to Consolidated Financial Statements)
1.
LINES OF CREDIT AND LONG-TERM DEBT
The amounts outstanding under the Parent Company’s long-term debt consisted of the following as of the dates indicated:
The following table presents aggregate contractual debt maturities of all long-term debt for the Parent Company:
8.75% Notes due 2022 (the “8.75% Notes”)
On December 16, 2014 (the “Closing Date”), the Company completed the issuance of $350.0 million in aggregate principal amount of 8.75% Notes. The 8.75% Notes were issued at a 1.292% discount, mature on January 1, 2022, and bear a fixed interest rate of 8.75% payable semiannually, on January 1 and July 1 of each year, commencing July 1, 2015. The 8.75% Notes are the Company’s senior secured obligations, rank equally in right of payment with all of the Company’s existing and future senior obligations, including the WCC Term Loan Facility obligations defined below under the WCC Term Loan Facility and rank senior to all of the Company’s existing and future indebtedness that is expressly subordinated to the 8.75% Notes. The 8.75% Notes have not been registered under the Securities Act of 1933. In 2014, the Company capitalized debt issuance costs of $10.2 million in connection with the 8.75% Notes.
The Company may redeem all or part of the 8.75% Notes beginning on January 1, 2018 at the redemption prices set forth in the 8.75% Notes, and prior to January 1, 2018 at 100% of the principal amount plus the applicable premium described in the 8.75% Notes agreement. In addition, at any time prior to January 1, 2018, the Company may redeem up to 35% of the aggregate principal amount of the 8.75% Notes with the net cash proceeds of certain equity offerings at a redemption price equal to 108.75% of the principal amount of the 8.75% Notes to be redeemed, together with accrued and unpaid interest, if any, to the redemption date, subject to certain conditions.
The 8.75% Notes are guaranteed by Westmoreland Energy LLC, Westmoreland Mining LLC and Westmoreland Resources, Inc. and their respective subsidiaries (other than Absaloka Coal, LLC, Westmoreland Risk Management, Inc. and certain other immaterial subsidiaries). The 8.75% Notes are not guaranteed by Westmoreland Canada LLC or any of its
WESTMORELAND COAL COMPANY
SCHEDULE I - NOTES TO FINANCIAL STATEMENTS
(Parent Company Information - See Notes to Consolidated Financial Statements)
subsidiaries, nor are they guaranteed by Westmoreland Resources GP, LLC or Westmoreland Resource Partners, LP or any of its subsidiaries, referred to as the Non-guarantors.
The 8.75% Notes and the guarantees are secured equally and ratably with the WCC Term Loan Facility (i) by first priority liens on substantially all of the Company’s and the guarantor parties’ tangible and intangible assets (excluding certain equity interests, mineral rights and sales contracts and certain assets subject to existing liens) and (ii) subject to the WCC Revolving Credit Facility, a second priority lien on substantially all cash, accounts receivable and inventory of the Company and the guarantors, and any other property with respect to, evidencing or relating to such cash, accounts receivable and inventory (whether now owned or hereinafter arising or acquired) and the proceeds and products thereof, subject in each case to permitted liens and certain exclusions (the “Notes Collateral”). The Notes Collateral is shared equally with the lenders under the WCC Term Loan Facility, who hold identical first and second priority liens, as applicable, on the Notes Collateral.
The 8.75% Notes restrict the Company’s and its restricted subsidiaries’ ability to, among other things, (i) incur, assume or guarantee additional indebtedness or issue preferred stock; (ii) declare or pay dividends on, or make other distributions in respect of, their capital stock; (iii) purchase or redeem or otherwise acquire for value any capital stock or subordinated indebtedness; (iv) make investments, other than permitted investments; (v) create certain liens or use assets as security; (vi) enter into agreements restricting the ability of any restricted subsidiary to pay dividends, make loans, or any other distributions to the Company or other restricted subsidiaries; (vii) engage in transactions with affiliates; and (viii) consolidate or merge with or into other companies or transfer all or substantially all of their assets.
The 8.75% Notes contain, among other provisions, events of default and various affirmative and negative covenants. As of December 31, 2015, the Company was in compliance with all covenants for the 8.75% Notes.
WCC Term Loan Facility due 2020
Effective as of the Closing Date, the Company entered into a WCC Term Loan Facility which provided for a $350.0 million term loan facility with a single advance made on the Closing Date. The WCC Term Loan Facility was issued at a 2.5% discount and matures on December 16, 2020. Borrowings under the WCC Term Loan Facility initially bear interest at one-month LIBOR plus 6.50%. The interest rate at December 31, 2015 was 7.50%. In 2014, the Company capitalized debt issuance costs of $8.4 million in connection with the WCC Term Loan Facility.
The WCC Term Loan Facility contains customary affirmative covenants, negative covenants, and events of default. Pursuant to the terms and provisions of the Guaranty and Collateral Agreement, dated the Closing Date, the obligations under the WCC Term Loan Facility are secured by identical first and second priority liens, as applicable, on the Notes Collateral. As of December 31, 2015, the Company was in compliance with all covenants for the WCC Term Loan Facility.
The WCC Term Loan Facility is guaranteed by Westmoreland Energy LLC, Westmoreland Mining LLC, Westmoreland Resources, Inc. and certain other direct and indirect subsidiaries of the Company (other than Absaloka Coal, LLC, Westmoreland Risk Management, Inc., Westmoreland Canada, LLC, Westmoreland Resources GP, LLC, Westmoreland Resource Partners, LP and certain other immaterial subsidiaries).
WCC Term Loan Facility Add-on
On January 22, 2015, the Company amended the WCC Term Loan Facility to increase the borrowings by $75.0 million, for an aggregate principal amount of $425.0 million. The amendments to the WCC Term Loan Facility were made in connection with the acquisition of Buckingham Coal Company, LLC. Net proceeds were $71.0 million after a 2.5% discount, 1.5% broker fee, a consent fee of 1.17%, and $0.1 million of additional debt issuance costs.
In conjunction with the Kemmerer Drop, the Company amended the WCC Term Loan Facility to remove Kemmerer as a guarantor. In addition, $94.1 million of the proceeds received from WMLP related to the Kemmerer Drop were used to pay down the WCC Term Loan Facility.
WCC Revolving Credit Facility
During the first quarter of 2014, the Company amended its WCC Revolving Credit Facility to increase the maximum available borrowing amount to $60.0 million. On December 16, 2014, the Company further amended the WCC Revolving Credit Facility, or the Second Amended and Restated Loan Agreement, decreasing the maximum borrowing amount to $50.0 million in the aggregate, consisting of a $30.0 million sub-facility available in the U.S. and a $20.0 million sub-facility available in Canada. Pursuant to a June 2, 2015 amendment to the WCC Revolving Credit Facility, Westmoreland has a total aggregate borrowing capacity of $75.0 million between June 15th and August 15 of each year. The revolver may support an equal amount of letters of credit, which would reduce the balance available under the revolver. At December 31, 2015,
WESTMORELAND COAL COMPANY
SCHEDULE I - NOTES TO FINANCIAL STATEMENTS
(Parent Company Information - See Notes to Consolidated Financial Statements)
availability under the WCC Revolving Credit Facility was $28.2 million with an outstanding balance of $19.8 million supporting letters of credit and a $2.0 million drawn on the revolver. All extensions of credit under the revolver are collateralized by a first priority security interest in and lien upon the inventory and accounts receivable of substantially all of the Company’s subsidiaries (other than Absaloka Coal, LLC, Westmoreland Risk Management, Inc.,Westmoreland Resources GP, LLC, Westmoreland Resource Partners, LP and certain other immaterial subsidiaries). Pursuant to the Intercreditor Agreement, the holders of the 8.75% Notes and the WCC Term Loan Facility have a subordinate lien on these assets. The revolver has a maturity date of December 31, 2018. The Company capitalized debt issuance costs of $0.7 million in 2014 related to the revolver amendments.
Borrowings under the Second Amended and Restated Loan Agreement initially bear interest either at a rate 0.75% in excess of the base rate (as detailed in the Second Amended and Restated Loan Agreement) or at a rate 2.75% per annum in excess of LIBOR, at the Borrowers’ election. An unused line fee of 0.50% per annum is payable monthly on the average unused amount of the revolver.
The loan agreement contains various affirmative, negative and financial covenants. Financial covenants in the agreement include a fixed charge coverage ratio and an EBITDA measure. The fixed charge coverage ratio must meet or exceed a specified minimum. The EBITDA covenant requires a minimum amount of EBITDA to be achieved. The Company met these covenant requirements as of December 31, 2015.
EXHIBIT INDEX
Attached as Exhibit 101 to this report are documents formatted in XBRL (Extensible Business Reporting Language). The financial information contained in the XBRL-related document is "unaudited" or "unreviewed."