Item 1. Business
Overview
We are a low-cost producer and marketer of high-value thermal coal to large electric utilities with coal-fired power plants under long-term coal sales contracts. We also market to industrial users, and are the largest producer of surface mined coal in Ohio. We focus on acquiring thermal coal reserves that we can efficiently mine with our large-scale equipment and take advantage of close customer proximity through mine-mouth power plants and strategically located rail and barge transportation. Our reserves and operations are well positioned to serve our primary market areas of the Midwest, Northeast and Rocky Mountain regions of the United States ("U.S."). Our operations are located in Ohio and Wyoming. We sold 7.8 million tons of coal in 2016.
Westmoreland Resource Partners, LP is a Delaware limited partnership listed on the New York Stock Exchange ("NYSE") under the ticker symbol "WMLP." We began doing business in 1985, in Coshocton, Ohio, as a contract-mining service to a mining division of a major oil company. In 1989, we transitioned from a contract miner into a producer of coal using our own coal reserves. On July 19, 2010 we completed our initial public offering and moved our headquarters to Columbus, Ohio. On December 31, 2014, our general partner ("GP") was acquired by WCC, a Delaware corporation, and our executive offices were moved to Englewood, Colorado. WCC directly owns 100% of our GP and, as of the date of this filing, 93.72% of the beneficial limited partner interest on a fully diluted basis. We are managed by WCC through our GP, and all executives, officers and employees who provide services to us (which are approximately 640 employees) are employed by WCC. WCC’s common stock trades on the NASDAQ under the symbol “WLB.” We conduct our operations through our subsidiaries and our principal sources of cash are distributions from our operating subsidiaries. We operate in a single business segment and have seven operating subsidiaries. See Exhibit 21.1 - List of Subsidiaries for an organizational chart. The following map shows our current operations:
Series B Convertible Units
On October 28, 2016, we issued 4,512,500 Series B Convertible Units representing limited partner interests in the Partnership (the “Series B Units”) to WCC in exchange for WCC’s 4,512,500 common units (the “Exchange”). Upon issuance of the Series B Units in the Exchange, WCC’s common units were canceled. The Series B Units do not share in distributions with the common units and are convertible at the option of the holder on a one-for-one basis into common units on the day after the record date for a cash distribution on the common units in which the Partnership is unable to make such a distribution without exceeding its restricted payment basket under the 2014 Financing Agreement (as defined in Note 13. Long-Term Debt to the consolidated financial statements). The Series B Units will convert automatically upon a change of control or a dissolution or liquidation of the Partnership. The Series B Units have the same voting rights as if they were outstanding common units and will vote together with the common units as a single class. In addition, the Series B Units are entitled to vote as a separate class on any matters that materially adversely affect the rights or preferences of the Series B Units in relation to other classes of partnership interests or as required by law. Concurrently with the Exchange, we entered into Amendment No. 2 to the Partnership Agreement (as defined in Note 1. Organization And Presentation and Note 17. Partners' Capital And Convertible Units to the consolidated financial statements), which established the terms of the Series B Units.
WESTMORELAND RESOURCE PARTNERS, LP AND SUBSIDIARIES
Properties
During 2016, WMLP operated one surface mine in Wyoming and four active mining complexes in Ohio comprising ten surface mines. The Ohio operations include a river terminal on the Ohio River, two washing facilities, two rail loadout facilities and a tipple facility. The mines are a combination of area, contour, auger and highwall mining methods using truck/shovel and truck/loader equipment along with large production dozers. WMLP owns and operates six augers throughout its mining complexes. WMLP also utilizes highwall miner systems. WMLP owns or leases most of the equipment utilized in its mining operations and employs preventive maintenance and rebuild programs to ensure that its equipment is well maintained. During 2016, WMLP leased or subleased to others approximately 24.3 million tons of the total tons owned or controlled by WMLP. We believe that we have satisfied all lease conditions in order to retain the properties and keep the leases in place.
Our reported proven and probable coal reserves are those we believe can be economically and legally extracted or produced at the time of the filing of this Annual Report on Form 10-K. In determining whether our proven and probable coal reserves meet this economic and legal standard, we take into account, among other things, our potential ability or inability to obtain mining permits, the possible necessity of revising mining plans, changes in future cash flows caused by changes in estimated future costs, changes in mining permits, variations in quantity and quality of coal, and varying levels of demand and their effects on selling prices. The following table provides coal reserve quantities from mines we own or control:
(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)
Reserve engineering is a process of estimating underground accumulations of coal that cannot be measured in an exact way. The accuracy of any reserve estimate depends on the quality of available data, the interpretation of such data and price and cost assumptions made by our reserve engineers. In addition, the results of mining, testing and production activities may justify revision of estimates that were made previously. If significant, such revisions would change the schedule of any further production and development of reserves. Accordingly, reserve estimates may differ from the quantities of coal that are ultimately recovered.
Substantially all of our properties and assets are encumbered by liens securing our and our subsidiaries’ outstanding indebtedness. In addition, borrowings under the Revolver are secured by first priority liens on our and our wholly owned subsidiaries' accounts receivable, inventory and certain other specified assets. See Note 13. Long-Term Debt to the consolidated financial statements.
WESTMORELAND RESOURCE PARTNERS, LP AND SUBSIDIARIES
The following table provides summary information regarding our principal mining operations as of December 31, 2016 (all tons data presented in thousands):
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(1) These mines were inactive during 2016.
(2) American Electric Power Company, Inc. (“AEP”); East Kentucky Power Cooperative (“EKPC”)
WESTMORELAND RESOURCE PARTNERS, LP AND SUBSIDIARIES
Cadiz. The Cadiz complex consists of the Sandy Ridge, Harrison, Daron, Harrah and Ellis mines. Coal produced from these mines is trucked either to our Bellaire river terminal on the Ohio River and then transported by barge to the customer, trucked directly to our customer, trucked to our Cadiz rail loadout facility on the Ohio Central Railroad and then transported by rail to the customer, or trucked to our Strasburg washing facility then transported by truck to the customer after processing is completed. This mine uses the area, contour, auger and highwall miner methods of surface mining.
Tuscarawas. The Tuscarawas complex consists of the East Canton, Garrett, Hunt and Stillwater mines. Coal produced from these mines is transported by truck directly to our customers, trucked to our Barb Tipple blending and coal crushing facility or trucked to our Conesville or Strasburg washing facilities. The coal is then transported by truck to the customer after washing is completed. This mine uses the area, contour, auger and highwall miner methods of surface mining.
Belmont. The Belmont complex consists of the Speidel, Shugert, Buttermilk and Wheeling Valley mines. Coal produced from these mines is primarily transported to our Bellaire river terminal on the Ohio River where it is crushed and blended and then transported by barge to the customer, or it is transported by truck to our Barb Tipple blending and crushing facility which is adjacent to a customer's power plant near Coshocton, Ohio, or it is transported to our Conesville washing facility and then transported by truck to the customer. This mine uses area, contour, auger and highwall miner methods of surface mining.
New Lexington. The New Lexington complex consists of the Avondale and New Lexington mines. Coal produced from these mines is transported by truck or delivered via off-highway trucks to our New Lexington rail loadout facility on the Ohio Central Railroad where it is then transported by rail to the customer or to our Barb Tipple facility. Some of the coal production from this mine is trucked to our Conesville washing facility and then transported by truck to the customer. This mine uses the area and auger methods of surface mining.
Kemmerer. The Kemmerer mine in Wyoming transports the coal it produces via conveyor belt to the adjacent Naughton Power Station or it is shipped via short haul rail or truck to various industrial customers. This mine utilizes truck, shovel and dozer surface mining methods.
Customers
Our primary customers are electric utility companies that purchase coal for terms of one year or longer. We also supply coal on a short-term or spot market basis for some of our customers. We provide coal delivery via conveyor belt to our mine-mouth customers and also sell coal on a Freight On Board ("FOB") basis to our other customers via truck, rail or barge. The purchaser of coal normally bears the cost of transportation and risk of loss from load-out to its final destination. In 2016, WMLP derived approximately 77% of its revenues from coal sales to three customers: AEP (38%), PacifiCorp Energy, Inc. (29%), and East Kentucky Power Cooperative (10%). We sell the majority of our WMLP tons under contracts with a weighted average remaining supply obligation term of approximately two years. A portion of these sales were facilitated by coal brokers.
The Kemmerer mine supplies the adjacent Naughton Power Station via conveyor belt under an agreement that expires in December 2021. The Kemmerer mine also supplies various industrial customers, including Tronox - Green River and Granger and Tata Chemicals North America Inc., through long-term contracts extending to 2026. These industrial customers are supplied via Union Pacific rail and truck. Prices under the supply agreements are based upon certain actual mine costs and certain inflation/commodity indices.
Long-term Coal Supply Contracts
As is customary in the coal industry, we enter into long-term supply contracts (one year or greater in duration) with substantially all of our customers. These contracts allow customers to secure an assured supply for their future needs and provide us with greater predictability of sales volumes and prices. For the year ended December 31, 2016, approximately 98.2% of our coal tons sold were sold under long-term supply contracts. We sell the remainder of our coal through short-term contracts and on the spot market.
The terms of our coal supply contracts result from competitive bidding and extensive negotiations with each customer. Consequently, the terms can vary significantly by contract, and can cover such matters as price adjustment features, price reopener terms, coal quality requirements, quantity adjustment mechanisms, permitted sources of supply, future regulatory changes, extension options, force majeure provisions and termination and assignment provisions. Some long-term contracts provide for a predetermined adjustment to the stipulated base price at specified times or periodic intervals to account for changes due to inflation or deflation in prevailing market prices. In addition, most of our contracts contain provisions to adjust the base price due to new statutes, ordinances or regulations that influence our costs of production. Some of our contracts also contain
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provisions that allow for the recovery of costs impacted by modifications or changes in the interpretations or application of applicable government statutes.
Price reopener provisions are present in several of our long-term contracts. These price reopener provisions may automatically set a new price based on prevailing market price or, in some instances, require the parties to agree on a new price, sometimes within a specified range. In a limited number of contracts, failure of the parties to agree on a price under a price reopener provision can lead to termination of the contract.
Quality and volume are stipulated in the coal supply contracts. In some instances, buyers have the option to change annual or monthly volumes. Most of our coal supply contracts contain provisions that require us to deliver coal with specific characteristics, such as heat content, sulfur, ash, hardness and ash fusion temperature, that fall within certain ranges. Failure to meet these specifications can result in economic penalties, suspension or cancellation of shipments or termination of the contract.
Royalty Revenues
Tusky Coal Reserves - We 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, we sold the Tusky mining complex, and subleased the associated underground coal reserves to the purchaser in exchange for a royalty. There are six years remaining on our 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 us assign its interest to the sublessee for defined and predetermined consideration. For the years ended December 31, 2016 and 2015, we 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, we 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 right sales in 2016 or 2015. For each of the years ended December 31, 2016 and 2015, WMLP generated $0.9 million in oil and gas royalty revenue.
Limestone Revenues - At our Daron and Strasburg mining complexes, limestone is removed in order to access the underlying coal. We sell this limestone to a third party who crushes it before selling it to local governmental authorities, construction companies and individuals. The third party pays us for this limestone based on a percentage of the revenue it receives from the limestone sales. For the years ended December 31, 2016 and 2015, we produced and sold 0.4 million and 0.7 million tons of limestone, respectively. Revenues from limestone sales included $1.8 million and $2.9 million for the same time periods, respectively.
Reclamation
Reclamation expenses are a significant part of any coal mining operation. Prior to commencing mining operations, a company is required to apply for numerous permits in the state where the mining is to occur. Before a state will approve and issue these permits, it requires the mine operator to present a reclamation plan which meets regulatory criteria and to secure a surety bond to guarantee reclamation funding in an amount determined under state law. Bonding companies require posting of collateral, typically in the form of letters of credit or cash collateral, to secure the bonds. See Note 6. Restricted Investments And Bond Collateral to the consolidated financial statements for our cash deposits, restricted investments and reclamation surety bonds. While bonds are issued against reclamation liability for a particular permit at a particular site, collateral posted is not allocated to a specific bond, but instead is part of a collateral pool supporting all bonds issued by a particular bonding company. Bonds are released in phases as reclamation is completed in a particular area.
Competition
The North American coal industry is intensely competitive. In addition to competition from other coal producers, we compete with producers of alternative fuels used for electrical power generation, such as nuclear energy, natural gas, hydropower, petroleum, solar and wind. Costs and other factors such as safety, environmental and regulatory considerations relating to alternative fuels affect the overall demand for coal as a fuel.
The majority of our mines focuses on niche coal markets where we take advantage of long-term coal contracts with neighboring power plants. These mines gives us a competitive advantage based on two factors:
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we are among the most economic suppliers to our principal customers as a result of transportation advantages over our competitors; and
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nearly all of the power plants we supply were specifically designed to use our coal.
The Ohio operations do not compete with producers of metallurgical coal or lignite. However, we do have limited competition from producers of Powder River Basin coal (sub-bituminous coal) in our target market area for bituminous coal. WMLP competes on the basis of delivered price, coal quality and reliability of supply. Its principal direct competitors are other coal producers, including (listed alphabetically) Alliance Resource Partners, L.P., Alpha Natural Resources, CONSOL Energy, Contura Energy, Foresight Energy, Hallador Energy Company, Murray Energy Corporation, Peabody Energy Corp., Rhino Resource Partners, L.P. and various other smaller, independent producers.
Washing Facilities
Depending on coal quality and customer requirements, some raw/crushed coal may be shipped directly from the mine to the customer. However, the quality of some raw coal does not allow direct shipment to the customer without putting the coal through a washing process that physically separates impurities from the coal. This processing upgrades the quality and heating value of the coal by generally removing ash, but it entails additional expense and results in some loss of coal. The Partnership owns and operates two washing facilities as follows:
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Strasburg (Strasburg, Ohio): Throughput capacity of 200 tons of raw coal per hour and operated at a 50.0% utilization rate in 2016;
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Conesville (Coshocton County, Ohio): Throughput capacity of 500 tons of raw coal per hour and operated at an 83.0% utilization rate in 2016 from January to April until it was idled the remainder of the year due to poor market conditions. This facility is adjacent to a customer’s power plant.
Seasonality
Our coal business has historically experienced variability in its results due to the effect of seasons. We are impacted by seasonality due to weather patterns and our customers’ annual maintenance outages which typically occur during the second quarter. In addition, our customers generally respond to seasonal variations in electricity demand based upon the number of heating degree days and cooling degree days. Due to stockpile management by our customers, our coal sales may not experience the same direct seasonal volatility; however, extended mild weather patterns can impact the demand for our coal. 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 some 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
Safety
Following passage of The Mine Improvement and New Emergency Response Act of 2006, amending the Federal Mine Safety and Health Act of 1977, MSHA significantly increased the oversight, inspection and enforcement of safety and health standards and imposed safety and health standards on all aspects of mining operations. There has also been a dramatic increase in the dollar penalties assessed by MSHA for citations issued over the past several years. Most of the states in which we operate have inspection programs for mine safety and health. Collectively, federal, state and provincial safety and health regulations in the coal mining industry are comprehensive and pervasive systems for protection of employee health and safety. Safety is a core value of Westmoreland Resource Partners, LP. We use a grass roots approach, encouraging and promoting employee involvement in safety and accept input from all employees; we feel employee involvement is a pillar of our safety excellence. Safety performance at our mines was as follows:
WESTMORELAND RESOURCE PARTNERS, LP AND SUBSIDIARIES
Regulations
We are subject to extensive regulation with respect to environmental and other matters by federal, state, and local authorities in the U.S. Regulations to which we are subject include, but are not limited to, the following:
The U.S. Environmental Protection Agency (the "EPA") and/or other authorized federal or state agencies administer and enforce these U.S. regulations. We are also subject to extensive regulation regarding safety and health matters pursuant to the United States Mine Safety and Health Act of 1977, which is enforced by the U.S. Mine Safety and Health Administration (“MSHA”). Non-compliance with federal, tribal and state laws and regulations could subject us to material administrative, civil or criminal penalties or other liabilities, including suspension or termination of operations. In addition, we may be required to make large and unanticipated capital expenditures to comply with future laws, regulations or orders as well as future interpretations and more rigorous enforcement of existing laws, regulations or orders. Our reclamation obligations under applicable environmental laws will be substantial. Certain of our coal sales agreements contain government imposition provisions that allow the pass-through of compliance costs in some circumstances.
The following provides summaries of certain U.S. federal regulations to which we are subject and their effects on us:
Surface Mining Control and Reclamation Act ("SMCRA"). SMCRA establishes minimum national operational, reclamation and closure standards for all surface coal mines. SMCRA requires that comprehensive environmental protection and reclamation standards be met during the course of and following completion of coal mining activities. Permits for all coal mining operations must be obtained from the Federal Office of Surface Mining Reclamation and Enforcement (“OSM”), or, where state regulatory agencies have adopted federally approved state programs under SMCRA, the appropriate state regulatory authority. States that operate federally approved state programs may impose standards that are more stringent than the requirements of SMCRA and OSM’s regulations and, in many instances, have done so. Permitting under SMCRA has generally become more difficult in recent years. This difficulty in permitting affects the availability of coal reserves at our coal mines. In January 2016, the Federal Bureau of Land Management announced a moratorium on new coal leases on federal lands. The moratorium does not affect existing leases. It is our policy to comply in all material respects with the requirements of the SMCRA and the state and tribal laws and regulations governing mine reclamation.
In December 2016, the OSM published the final Stream Protection Rule to reduce the environmental impact of surface coal mining operations. The rule included the expansion of baseline data requirements and post-mining restoration requirements. Under the Congressional Review Act, Congress approved H.J. Res. 38, disapproving the Stream Protection Rule. President Trump signed H.J. Res. 38 on February 16, 2017. The regulations in effect are those that were in place on January 18, 2017. OSM is in the process of developing a final rule for publication in the Federal Register to amend all the regulations altered by the Stream Protection Rule back to the form in which those regulations existed on January 18, 2017.
Clean Air Act and Related Regulations. The U.S. Clean Air Act (“CAA”), and comparable state laws that regulate air emissions affect coal mining operations both directly and indirectly. Direct impacts on coal mining and processing operations include Clean Air Act permitting requirements and emission control requirements relating to air pollutants, including particulate matter, which may include controlling fugitive dust. The Clean Air Act indirectly affects coal mining operations by extensively regulating the emissions of particulate matter, sulfur dioxide, nitrogen oxides, mercury and other compounds emitted by coal-fired power plants. In recent years, Congress has considered legislation that would require increased reductions in emissions of sulfur dioxide, nitrogen oxide and mercury, as well as greenhouse gases ("GHG"). The air emissions programs, regulatory initiatives and standards that may affect our operations, directly or indirectly, include, but are not limited to, the following:
WESTMORELAND RESOURCE PARTNERS, LP AND SUBSIDIARIES
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Greenhouse Gas Emissions Standards. In August of 2015, the EPA finalized standards for greenhouse gases for new and modified electric generating units ("EGUs") referred to as “new source performance standards” ("NSPS"). The final NSPS for coal-fired EGUs is set at 1,400 pounds of CO2 / megawatt hour on an average annual basis which would, with few possible exceptions, require the installation of partial carbon capture and sequestration at new or modified coal-fired EGUs. Under the CAA, new source performance standards like the GHG NSPS have binding effect from the date of the proposal, which in this case was January 8, 2014. Therefore, any new coal-fired EGU must comply with this standard, which is likely to be a major obstacle to the construction and development of any new coal-fired generation capacity. States and industry challenged the rule in the D.C. Circuit court, with oral arguments scheduled for April 17, 2017. Existing coal-fired generation, however, is also now subject to GHG performance standards that the EPA asserts will reduce GHG emissions from the power sector by 32% from 2005 levels by 2030. At the same time the EPA issued the GHG NSPS, the EPA finalized existing source standards for fossil-fuel fired power plants, which the EPA refers to as the Clean Power Plan. The final Clean Power Plan imposes stringent standards on existing fossil-fuel fired EGUs that reflect the EPA’s assessment of the “best system of emission reduction,” ("BSER") including (1) average heat rate improvements of 6% for coal-fired power plants; (2) the re-dispatch of power based on an assumption that underutilized capacity at natural gas combined cycle facilities can be increased to an average of 75% of net summer capacity; and (3) the substitution of coal generation with renewable energy. These existing source standards are implemented by the states, which must meet individual GHG emission “goals” beginning in 2022 with phased reductions through 2030. Each state can choose either a rate-based or a mass-based goal that reflects the mix of natural gas and coal-fired generation in the state. The final goals have a greater impact on states with substantial coal-fired generation; Wyoming, for example, is faced with greater than 40% emission reductions from a 2012 baseline. Under the rule, the states had until September of 2016 to submit plans to the EPA to implement and enforce the state-specific BSER, although two-year extensions could have been requested by states in an initial submittal. States and industry groups challenged the rule in the U.S. Court of Appeals for the D.C. Circuit and requested a stay pending judicial review. Although the D.C. Circuit denied the stay request, in February of 2016, the U.S. Supreme Court issued a stay of the Clean Power Plan pending judicial review of the rule, including potential review by the Supreme Court. The stay delayed the implementation of the rule, including the state plan submittal dates. The D.C. Circuit reviewed the rule under an expedited briefing schedule, and an en banc panel heard oral arguments on September 27, 2016. If upheld by the courts, these rules have the potential to adversely affect our revenues and profitability, although it is difficult at this stage to determine the timing and extent of any such effects, or to determine the requirements of state plans resulting from these proposals that may ultimately be promulgated and require implementation. However, the Trump Administration has indicated that it intends to repeal the Clean Power Plan and it is uncertain whether it will be replaced. In June 2014, the U.S. Supreme Court in UARG v. the 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 2016, the EPA proposed a rule to comply with the U.S. Supreme Court’s ruling by limiting the requirement to obtain permits controlling emissions of greenhouse gases to new large sources of other air pollutants, such as volatile organic compounds or nitrogen oxides, which also emit 100,000 tons per year or more of CO2 (or modifications of these sources that result in an emissions increase of 75,000 tons per year or more of CO2e). Therefore the permit provisions addressing GHG emissions from large industrial sources, such as fossil-fuel fired EGUs, remain in place.
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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 the EPA to conduct a cost assessment but without vacatur, allowing the rule to remain in effect while the EPA conducted the rulemaking. On December 1, 2015, the EPA published a proposed supplemental finding that regulation of EGUs is still “appropriate and necessary” in light of the costs to regulate hazardous air pollutant emissions from the source category. On April 14, 2016, the EPA issued a final rule confirming its “appropriate and necessary” finding to regulate air toxics, including mercury, from power plants after considering
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costs. The final rule was immediately challenged in the U.S. Court of Appeals for the D.C. Circuit in Murray Energy Corp. v. the EPA and briefing is currently underway.
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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 dioxide and sulfur dioxide. Areas that are not in compliance (referred to as non-attainment areas) with these standards must take steps to reduce emissions levels. Meeting these limits may require reductions of nitrogen dioxide and sulfur dioxide emissions. Although our operations are not currently located in non-attainment areas, we could be required to incur significant costs to install additional emissions control equipment, or otherwise change our operations and future development if that were to change. On June 22, 2010, the EPA published a final rule that tightens the NAAQS for sulfur dioxide. On February 17, 2012, the EPA published final NAAQS for nitrogen dioxide. On January 15, 2013, the EPA published final NAAQS for particulate matter; the EPA lowered the annual standard for particles less than 2.5 micrometers in diameter but maintained the NAAQS for particles less than 10 micrometers in diameter. The EPA finalized designations for the sulfur dioxide NAAQS in 2013 for a handful of counties and delayed designations for the remainder of the country. The EPA finalized additional designations on June 30, 2016, with a supplement on November 29, 2016. For the remaining areas, the areas will be designated by the date determined by the Sulfur Data Requirements Rule. The EPA finalized nonattainment designations for nitrogen dioxide in January 2012. We do not know whether or to what extent these developments might affect our operations or our customers’ businesses. In 2008, the EPA finalized the current 8-hour ozone standard. In October 2015, the EPA issued a final rule lowering the ozone standard further. Several industry and business groups, five states, and Murray Energy Corp. challenged the revised standard in the D.C. Circuit. Briefing has been completed and oral argument is scheduled for April 19, 2017. The Trump Administration also has indicated that it may revisit the standard. While it is likely that these and any future developments resulting in stricter NAAQS will to some degree adversely affect us, it is difficult at this stage to determine the timing and extent of such effects.
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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 oxides pursuant to a cap-and-trade program similar to the system now in effect for acid rain. In 2008, the U.S. Court of Appeals for the District of Columbia Circuit found that the CAIR was fatally flawed, but ultimately agreed to allow it to remain in place pending the EPA’s development of a replacement rule because of concerns about potential disruptions. In June 2011, the EPA finalized the CSAPR as a replacement rule to the CAIR, which requires 28 states in the Midwest and Eastern seaboard of the United States to reduce power plant emissions that cross state lines and contribute to ozone and/or fine particle pollution in other states. Under the CSAPR, the first phase of the nitrogen oxides and sulfur dioxide emissions reductions would commence in 2012 with further reduction effective in 2014. On December 15, 2011, the EPA finalized a supplemental rule-making to require Iowa, Michigan, Missouri, Oklahoma and Wisconsin to make summertime reductions to nitrogen oxide emissions under the CSAPR ozone-season control program. However, on December 30, 2011, the U.S. Court of Appeals for the District of Columbia Circuit stayed the implementation of CSAPR pending resolution of judicial challenges to the rules and ordered the EPA to continue enforcing the CAIR until the pending legal challenges have been resolved. In August 2012, the U.S. Court of Appeals vacated the CSAPR in a 2-to-1 decision and left the CAIR standards in place. In April 2014, the U.S. Supreme Court reversed the D.C. Circuit decision that vacated the CSAPR and remanded the cases for further proceedings consistent with the Court’s opinion, which acknowledged the possibility that under certain circumstances some states may have a basis to bring a particularized, as-applied challenge to the rule. The EPA filed a motion with the D.C. Circuit to lift its stay of the CSAPR and to toll for three years all deadlines that had not already passed as of the date the stay was granted. The D.C. Circuit granted the EPA’s motion in October 2014, and scheduled oral argument on the remaining challenge to the CSAPR for March 2015. In November 2014, the EPA issued a ministerial rule aligning the CSAPR implementation dates with the Court’s order, with phase 1 reductions began in January 2015, and more stringent phase 2 reductions in January 2017. In July 2015, the D.C. Circuit remanded to the EPA portions of the 2014 sulfur dioxide and ozone budgets on grounds the reductions were greater than necessary to reduce impacts on downwind states, but did not vacate any portion of the rule. The EPA has indicated that it will address these issues in future rulemakings, but that phase 1 reductions began in January 2015, with more stringent phase 2 reductions in January 2017 as necessary. In September 2016, the EPA finalized an update to CSAPR ozone season program that lowered the ozone season emission budgets for the affected states. The update aligned compliance with the July 2018 attainment date for the 2008 ozone NAAQS.
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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
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review program under certain circumstances requires existing coal-fired power plants, when modifications to those plants significantly change emissions, to install the more stringent air emissions control equipment required of new plants, and concerns about potential failures to comply have resulted in a number of high-profile enforcement actions and settlements over the years resulting in some instances in settlements under which operators install expensive new emissions control equipment. The Acid Rain program under Title IV of the CAA continues to impose limits on overall sulfur dioxide and nitrogen oxide emissions from regulated EGUs. In June 2013, President Obama issued a Climate Action Plan, which included a focus on methane reductions from coal mines. In January 2015, the Administration issued its methane strategy, but it did not include requirements for coal mines. In 2014 the D.C. Circuit upheld the 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 Resource Partners, LP. Our mines do not produce “compliance coal” for purposes of the Clean Air Act. Compliance coal is coal containing 1.2 pounds or less of sulfur dioxide per million British thermal unit. This restricts our ability to sell coal to power plants that do not utilize sulfur dioxide emission controls and otherwise leads to a price discount based, in part, on the market price for sulfur dioxide emission allowances under the Clean Air Act. Our coal also contains about fifty percent more ash content than our primary competitors, which can translate into a cost disadvantage where post-combustion coal ash must be land filled.
Clean Water Act. The Clean Water Act (“CWA”) and corresponding state and local laws and regulations affect coal mining and power generation operations by restricting the discharge of pollutants, including dredged or fill materials, into waters of the U.S. The CWA provisions and associated state and federal regulations are complex and subject to amendments, legal challenges and changes in implementation. In May 2015, the EPA and the U.S. Army Corps of Engineers (the "Corps") jointly issued a final rule to clarify which waters and wetlands are subject to regulation under the CWA. The implementation of this rule was stayed nationwide in October 2015. Recent court decisions, pending court challenges, regulatory actions and proposed legislation have created uncertainty over CWA jurisdiction and permitting requirements that could either increase or decrease the cost and time spent on CWA compliance. In January 2017, the Corps issued general nationwide permits for specific activities that are similar in nature and that are determined to have minimal adverse environmental effects. The permits will become effective in March 2017. The Corps reinstated the use of Nationwide Permit 21 for surface coal mining activities. In the event the acreage limits under the permit are exceeded, we will have to obtain individual permits from the Corps which will increase the processing time for future permit applications.
Endangered Species Act. The Federal Endangered Species Act (“ESA”), and similar state laws, protect species threatened with extinction. Protection of endangered and threatened species may cause us to modify mining plans or develop and implement species-specific protection and enhancement plans to avoid or minimize impacts to endangered species or their habitats. A number of species indigenous to the areas where we operate are protected under the ESA. Based on the species that have been identified and the current application of applicable laws and regulations, we do not believe that there are any species protected under the ESA or state laws that would materially and adversely affect our ability to mine coal from our properties.
Resource Conservation and Recovery Act. We may generate wastes, including “solid” wastes and “hazardous” wastes, that are subject to the federal Resource Conservation and Recovery Act (“RCRA”), and comparable state statutes, although certain mining and mineral beneficiation wastes and certain wastes derived from the combustion of coal currently are exempt from regulation as hazardous wastes under RCRA. The EPA has limited the disposal options for certain wastes that are designated as hazardous wastes under RCRA. Furthermore, it is possible that certain wastes generated by our operations that currently are exempt from regulation as hazardous wastes may in the future be designated as hazardous wastes, and therefore be subject to more rigorous and costly management, disposal and clean-up requirements.
The EPA determined that coal combustion residuals (“CCR”) do not warrant regulation as hazardous wastes under RCRA in May 2000. Most state hazardous waste laws do not regulate CCR as hazardous wastes. The EPA also concluded that beneficial uses of CCR, other than for mine filling, pose no significant risk and no additional national regulations of such beneficial uses are needed. However, the EPA determined that national non-hazardous waste regulations under RCRA are warranted for certain wastes generated from coal combustion, such as coal ash, when the wastes are disposed of in surface impoundments or landfills or used as minefill. The EPA Administrator Gina McCarthy signed the final rule relating to the disposal of CCR from electric utilities on December 19, 2014 and submitted it to the Federal Register for publication. The final rule regulates CCR as solid waste under RCRA. The final rule establishes national minimum criteria for existing and new CCR landfills, surface impoundments and lateral expansions. The criteria include location restrictions, design and operating criteria, groundwater monitoring and corrective action, closure requirements and post-closure care and recordkeeping, notification and Internet posting requirements. The rule is largely silent on the reuse of coal ash. These changes in the management of CCR could
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increase both our and our customers’ operating costs and potentially reduce their ability to purchase coal. In addition, contamination caused by the past disposal of CCR, including coal ash, could lead to citizen suit enforcement against our customers under RCRA or other federal or state laws and potentially reduce the demand for coal.
Comprehensive Environmental Response, Compensation and Liability Act. Under the Comprehensive Environmental Response, Compensation, and Liability Act ("CERCLA" or "Superfund") and similar state laws, responsibility for the entire cost of cleanup of a contaminated site, as well as natural resource damages, can be imposed upon current or former site owners or operators, or upon any party who released one or more designated “hazardous substances” at the site, regardless of the lawfulness of the original activities that led to the contamination. CERCLA also authorizes the EPA and, in some cases, third parties to take actions in response to threats to public health or the environment and to seek to recover from the potentially responsible parties the costs of such action. In the course of our operations, we may have generated and may generate wastes that fall within CERCLA’s definition of hazardous substances. We may also be an owner or operator of facilities at which hazardous substances have been released by previous owners or operators. We may be responsible under CERCLA for all or part of the costs of cleaning up facilities at which such substances have been released and for natural resource damages. We have not, to our knowledge, been identified as a potentially responsible party under CERCLA, nor are we aware of any prior owners or operators of our properties that have been so identified with respect to their ownership or operation of those properties. We also must comply with reporting requirements under the Emergency Planning and Community Right-to-Know Act and the Toxic Substances Control Act.
Climate Change Legislation and Regulations. Numerous proposals for federal and state legislation have been made relating to GHG emissions (including carbon dioxide) and such legislation could result in the creation of substantial additional costs in the form of taxes or required acquisition or trading of emission allowances. Many of the federal and state climate change legislative proposals use a “cap and trade” policy structure, in which GHG emissions from a broad cross-section of the economy would be subject to an overall cap. Under the proposals, the cap would become more stringent with the passage of time. The proposals establish mechanisms for GHG sources such as power plants to obtain “allowances” or permits to emit GHGs during the course of a year. The sources may use the allowances to cover their own emissions or sell them to other sources that do not hold enough emissions for their own operations. Some states, including California, and regional groups including a number of states in the northeastern and mid-Atlantic regions of the 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 the EPA’s GHG permitting rules to the extent they required permits based solely on emissions of GHG; however, the EPA has proposed a rule to comply with the U.S. Supreme Court’s ruling by limiting the requirement to obtain permits controlling emissions of greenhouse gases to large sources of other air pollutants, such as volatile organic compounds or nitrogen oxides, which also emit 100,000 tons per year or more of CO2 (or modifications of these sources that result in an emissions increase of 75,000 tons per year or more of CO2e). Underground coal mines remain subject to the EPA’s GHG Reporting Program, which requires mines to submit annual GHG emission estimates to the EPA, but that program has not been extended to surface coal mines.
The impact of GHG-related legislation and regulations, including a “cap and trade” structure, on us will depend on a number of factors, including whether GHG sources in multiple sectors of the economy are regulated, the overall GHG emissions cap level, the degree to which GHG offsets are allowed, the allocation of emission allowances to specific sources and the indirect impact of carbon regulation on coal prices. We may not recover from our customers the costs related to compliance with regulatory requirements imposed on us due to limitations in our agreements.
Passage of additional state or federal laws or regulations regarding GHG emissions or other actions to limit carbon dioxide emissions could result in fuel switching from coal to other fuel sources by electricity generators and thereby reduce demand for our coal or indirectly the prices we receive in general. In addition, political and regulatory uncertainty over future emissions controls have been cited as major factors in decisions by power companies to postpone new coal-fired power plants. If these or similar measures, such as controls on methane emissions from coal mines, are ultimately imposed by federal or state governments or pursuant to international treaties, our operating costs or our revenues may be materially and adversely affected. In addition, alternative sources of power, including wind, solar, nuclear and natural gas could become more attractive than coal in order to reduce carbon emissions, which could result in a reduction in the demand for coal and, therefore, our revenues. Similarly, some of our customers, in particular smaller, older power plants, could be at risk of significant reduction in coal burn or closure as a result of imposed carbon costs. The imposition of a carbon tax or similar regulation could, in certain situations, lead to the shutdown of coal-fired power plants, which would materially and adversely affect our revenues.
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Bonding Requirements. Federal and state laws require mine operators to assure, usually through the use of surety bonds, payment of certain long-term obligations, including the costs of mine closure and the costs of reclaiming the mined land. The costs of these bonds have fluctuated in recent years, and the market terms of surety bonds have generally become more favorable to us. Surety providers are requiring smaller percentages of collateral to secure a bond, which will require us to provide less cash to collateralize bonds to allow us to continue mining. These changes in the terms of the bonds have been accompanied, at times, by an increase in the number of companies willing to issue surety bonds. See Note 6. Restricted Investments And Bond Collateral to the consolidated financial statements for the amount of surety bonds posted and cash collateral for reclamation purposes.
Additional Information
We file annual, quarterly and current reports, proxy statements and other information with the Securities and Exchange Commission (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.westmorelandMLP.com, as soon as practicable after we file or furnish them with the SEC. You may also request copies of the documents, at no cost, by telephone at (855) 922-6463 or by mail at Westmoreland Resource Partners, LP, 9540 South Maroon Circle, Suite 300, Englewood, CO 80112. The information on our website is not part of this Annual Report on Form 10-K.
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Item 1A.
Item 1A. Risk Factors
Risks Related to Our Business
Our 2014 Financing Agreement contains operating and financial restrictions that restrict our distributions, business and financing activities.
Our 2014 Financing Agreement contains significant restrictions on our ability to incur additional liens or indebtedness, make fundamental changes or dispositions, make changes in the nature of our business, make certain investments, loans or advances, create certain lease obligations, make capital expenditures in excess of a certain amount, enter into transactions with affiliates, issue equity interests, and modify indebtedness, organizational and certain other documents. The 2014 Financing Agreement also contains covenants requiring us to maintain certain financial ratios and limits our ability to pay distributions to our unitholders, allowing such distributions only under specified circumstances.
The provisions of the 2014 Financing Agreement may affect our ability to obtain future financing, pursue attractive business opportunities, and allow for flexibility in planning for, and reacting to, changes in business conditions. In addition, a failure to comply with the provisions of the 2014 Financing Agreement could result in a default or an event of default that could enable our lenders to declare the outstanding principal of our debt under the 2014 Financing Agreement, together with accrued and unpaid interest, to be immediately due and payable. If the payment of such debt is accelerated, our assets may be insufficient to repay such debt in full, and our unitholders could experience a partial or total loss of their investment.
Our ability to comply with the covenants and restrictions contained in the 2014 Financing Agreement may be affected by events beyond our control that could hinder our ability to meet our financial forecasts, including prevailing economic, financial and industry conditions. If market or other economic conditions deteriorate, our ability to comply with these covenants may be impaired. If we violate any of the covenants or restrictions in the 2014 Financing Agreement, our indebtedness under the 2014 Financing Agreement may become immediately due and payable, and our lenders' commitment to make further loans to us may terminate. We might not have, or be able to obtain, sufficient funds to make these accelerated payments. In addition, our obligations under the 2014 Financing Agreement are secured by substantially all of our assets and, if we are unable to repay our indebtedness under the 2014 Financing Agreement, the lenders could seek to foreclose on such assets. For more information, see Note 13. Long-Term Debt to the consolidated financial statements.
Our debt levels may limit our flexibility in obtaining additional financing and in pursuing other business opportunities.
We have a substantial amount of indebtedness. At December 31, 2016, we had a total outstanding indebtedness of $306.2 million under our 2014 Financing Agreement. Our level of indebtedness could have significant consequences to us and our unitholders, including the following:
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our ability to obtain additional financing, if necessary, for working capital, capital expenditures (including acquisitions) or other purposes may be impaired or such financing may not be available on favorable terms;
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our ability to meet financial covenants may affect our flexibility in planning for and reacting to changes in our business, including possible acquisition opportunities;
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our need to use a portion of our cash flow to make principal and interest payments will reduce the amount of funds that would otherwise be available for operations, distributions, and future business opportunities;
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our increased vulnerability to competitive pressures or a downturn in our business or the economy generally; and
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our flexibility in responding to changing business and economic conditions.
These factors could have a material adverse effect on our business, financial condition, results of operations or prospects. Increases in our total indebtedness would increase our total interest expense costs. Our ability to service our indebtedness will depend upon, among other things, our future financial and operating performance, which will be affected by prevailing economic conditions and financial, business, regulatory and other factors, some of which are beyond our control. If our operating results are not sufficient to service our current or future indebtedness, we will be forced to take actions such as reducing or delaying our business activities, acquisitions, investments and/or capital expenditures, selling assets, restructuring or refinancing our indebtedness, or seeking additional equity capital or bankruptcy protection. We may not be able to effect any of these remedies on satisfactory terms, or at all.
WESTMORELAND RESOURCE PARTNERS, LP AND SUBSIDIARIES
Long-term sales and revenues could be significantly affected by environmental regulations and the effects of the environmental lobby.
Environmental regulations that have become increasingly stringent, as well as increased pressure from environmental activists, may reduce demand for our products. For example, a consortium of environmental activists is actively pushing to shut down one-third of the U.S. coal plants by 2020. They are actively lobbying the EPA to require cost-prohibitive pollution control equipment. Rocky Mountain Power, the owner of the Naughton Power Station located adjacent to our Kemmerer mine, which is our Kemmerer mine’s primary customer, has abandoned plans to convert Unit 3 at Naughton to 100% natural gas fueling. Instead, the owner has stated that it intends to retire Naughton Unit 3 at the end of 2017. This retirement will result in the loss of coal sales at our Kemmerer mine. However, Rocky Mountain Power stated that it will continue to consider potential alternatives to allow continued operation beyond 2017. In addition, price protections built into the contract that are in effect from 2017 to 2021 will partially offset the effects of lowered volume following the retirement 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, decreased operations or retirement, in order to avoid costly upgrades of pollution control equipment, and such steps, if taken, could result in a reduced demand for our products and materially and adversely affect our revenues and profitability.
In May 2015, the EPA and the Corps issued a final rule to clarify which waters and wetlands are subject to regulation under the CWA. The implementation of this rule was stayed nationwide in October 2015. In January 2017, the Corps issued general nationwide permits for specific activities, including surface coal mining activities. Permitting challenges may increase if our activities do not qualify for nationwide permit coverage. A change in CWA jurisdiction and permitting requirements could increase or decrease our permitting and compliance costs.
The EPA has executed a final rule relating to the disposal of CCR from electric utilities. The changes to the management of CCR could increase our and our customers’ operating costs and reduce sales of coal.
In December 2016, the OSM published the final Stream Protection Rule to reduce the environmental impact of surface coal mining operations. The rule included the expansion of baseline data requirements and post-mining restoration requirements. Under the Congressional Review Act, Congress approved H.J. Res. 38, disapproving the Stream Protection Rule. President Trump signed H.J. Res. 38 on February 16, 2017. The regulations in effect are those that were in place on January 18, 2017. OSM is in the process of developing a final rule for publication in the Federal Register to amend all the regulations altered by the Stream Protection Rule back to the form in which those regulations existed on January 18, 2017. If this rule is not amended, our permitting and compliance costs could increase.
In January 2016, the Federal Bureau of Land Management announced a moratorium on new coal leases on federal lands. The moratorium does not affect our existing federal leases. If the moratorium remains in force, it is unlikely to have a material impact on our ability to conduct future operations because we do not ordinarily bid on federal coal leases.
Certain provisions in our long-term supply contracts may provide limited protection during adverse economic conditions, may result in economic penalties, and/or may permit customers to terminate such contracts.
Price adjustment, "price re-opener" and other similar provisions in our 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 our business, financial condition and/or results of operations.
Coal supply contracts also typically contain force majeure provisions allowing temporary suspension of performance by our customers or us during the duration of specified events beyond the control of the affected party. Most of our coal supply contracts also contain provisions requiring us to deliver coal meeting quality thresholds for certain characteristics such as Btu, sulfur content, ash content, hardness and ash fusion temperature. Failure to meet these specifications could result in economic penalties, including price adjustments, the rejection of deliveries or termination of the contracts. In addition, certain of our supply contracts permit the customer to terminate the contract in the event of changes in regulations affecting our industry that increase the price of coal beyond a specified limit. Any events leading to the termination or suspension of one or more contracts could adversely affect our business, financial condition and/or results of operations. For more information, see Item 1 - Business - Long-term Coal Supply Contracts.
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We depend on supply contracts with a few customers for a significant portion of our revenues.
We sell a material portion of our coal under supply contracts. As of December 31, 2016, we had sales commitments for approximately 93.4% of our estimated coal production (including purchased coal to supplement our production) for the year ending December 31, 2017. When our current contracts with customers expire, our customers may decide not to extend existing contracts or enter into new contracts. For the year ended December 31, 2016, we derived 97.8% of our total revenues from coal sales to our ten largest customers (including their affiliates), with our top three customers (including their affiliates) accounting for 77.3% of such revenues.
In the absence of long-term contracts, our 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. In addition, interruption in the purchases by or operations of our principal customers could adversely affect our business, financial condition and/or results of operations. Examples of conditions that might cause our customers to reduce their purchases include unscheduled maintenance outages at our customers’ power plants, unseasonably moderate weather, 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. We may have difficulty identifying alternative purchasers of our coal if our existing customers suspend or terminate their contracts.
Additionally, certain of our long-term contracts are set to expire in the next several years. 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 our mines should we be unable to execute new long-term coal supply agreements for the affected mines. See Item 1 - Business - Customers and Item 1 - Business - Long-term Coal Supply Contracts.
We depend upon our ability to collect payments from our customers.
Our ability to receive payment for the coal we sell depends on the continued creditworthiness of our customers. Periods of economic volatility and tight credit markets increase the risk that we may not be paid.
If the creditworthiness of a customer declines, this would increase the risk that we may not be able to collect payment for some or all of the coal we delivered to that customer. 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 we are able to withhold shipments, we may decide to sell the customer’s coal on the spot market, which may be at prices lower than the contract price, or we may be unable to sell the coal at all.
Also, competition with other coal suppliers could force us to extend credit to customers on terms that could increase the risk of payment default.
In addition, we sell some of our coal to brokers who may resell our coal to end users, including utilities. These coal brokers may have only limited assets, making them less credit worthy than the end users. Under some of these arrangements, we have 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 our customers, whether an end user or a broker, could adversely affect our business, financial condition and/or results of operations.
A decline in demand for coal could adversely affect our ability to sell the coal we can produce and a decline in coal prices could render production from our coal reserves uneconomical.
Our results of operations and the value of our coal reserves are significantly dependent upon the prices we receive for our coal, as well as our ability to improve productivity and control costs. The prices we receive for coal depend upon factors beyond our control, including:
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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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a decline in prices under existing contracts where the pricing is tied to and adjusted periodically based on indices reflecting current market pricing;
WESTMORELAND RESOURCE PARTNERS, LP AND SUBSIDIARIES
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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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the level of 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; and
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market price fluctuations for sulfur dioxide emission allowances.
Any adverse change in these factors could result in a decline in demand and lower prices for our coal.
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. Furthermore, because we typically seek to enter into long-term arrangements for the sale of a substantial portion of our coal, the average sales price we receive for our coal may lag behind any general economic recovery.
Competition in the North American coal industry may adversely affect our revenues and results of operations.
Many of our competitors in the North American coal industry are major coal producers who have significantly greater financial resources than we do. The intense competition among coal producers may impact our ability to retain or attract customers and may therefore adversely affect our 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. Additionally, during the last several years, the U.S. coal industry has experienced increased consolidation, which has contributed to the industry becoming more competitive. Increased competition by coal producers or producers of alternate fuels could decrease the demand for, pricing of, or both, for our coal, adversely affecting our business, financial condition and/or results of operations. See Item 1 - Business - Competition.
Any changes in consumption patterns by utilities away from the use of coal, such as changes resulting from low natural gas prices, could affect our ability to sell the coal we produce.
We compete with coal producers in the Midwest, northeastern U.S. and Rocky Mountain regions and in other coal producing regions of the United States. The domestic demand for, and prices of, our coal primarily depend on coal consumption patterns of the domestic electric utility industry. Thermal coal accounted for 100% of our coal sales volume for the year ended December 31, 2016. During this period, 78.6% of our thermal coal sales were to electric utilities for use primarily as fuel for domestic electricity consumption. In addition to competing with other coal producers, we compete generally with producers of other fuels. The amount of coal consumed by the domestic electric utility industry is affected primarily by the overall demand for electricity, environmental and other governmental regulations, and the price and availability of competing fuels for power plants such as nuclear, natural gas and oil, as well as alternative sources of energy. For the first eleven months of 2016, the EIA estimates that coal consumption in the electric power sector totaled 612 million tons, or 93% of total U.S. coal consumption, a historic low, due to low natural gas prices paid by the electric generators that led to a significant increase in the share of natural gas-fired power generation. A further 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.
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The economic stability of these markets has a significant effect on the demand for coal and the level of competition in supplying these markets.
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. Further, legislation requiring, subsidizing or providing tax benefits for the use of alternative energy sources and fuels, or legislation providing financing or incentives to encourage continuing technological advances in this area, could further enable alternative energy sources to become more competitive with coal. Passage of these and other state or federal laws or regulations limiting carbon dioxide emissions could result in fuel switching, from coal to other fuel sources, by purchasers of our coal. Such laws and regulations could also mandate decreases in carbon dioxide emissions from coal-fired power plants, impose taxes on carbon emissions or require certain technology to capture and sequester carbon dioxide from coal-fired power plants. If these or similar measures are ultimately imposed by federal or state governments or pursuant to international treaty, our reserves and operating costs may be materially and adversely affected. Similarly, alternative fuels (non-fossil fuels) could become more attractive than coal in order to reduce carbon emissions, which could result in a reduction in the demand for coal and, therefore, our revenues.
Recently, the supply of natural gas has reached record highs and the price of natural gas has remained at depressed levels for sustained periods 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, 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.
Our business requires substantial capital expenditures, and we may not have access to the capital required to maintain full productive capacity at our mines.
Maintaining and expanding mines and infrastructure is capital intensive. Specifically, the exploration, permitting and development of coal reserves, mining costs, the maintenance of machinery and equipment and compliance with applicable laws and regulations require substantial capital expenditures. We must continue to invest capital to maintain or to increase our production. Decisions to increase our production levels could also affect our capital needs. We cannot assure you that we will be able to maintain our current production levels or generate sufficient cash flow, or that we will have access to sufficient financing to continue our production, exploration, permitting and development activities at or above our present levels, and we may be required to defer all or a portion of our capital expenditures. As of December 31, 2016, our liquidity of $30.1 million consisted of $15.1 million of cash and cash equivalents and $15.0 million of availability under our Revolver. Our results of operations, business and financial condition, as well as our ability to pay distributions to our unitholders may be materially adversely affected if we cannot make such capital expenditures.
The amount of estimated reserve replacement capital expenditures our general partner is required to deduct from operating surplus each quarter could increase in the future, resulting in a decrease in available cash from operating surplus that could be distributed to our unitholders.
Our partnership agreement requires our general partner to deduct from operating surplus each quarter estimated reserve replacement expenditures as opposed to actual reserve replacement expenditures in order to reduce disparities in operating surplus caused by fluctuating reserve replacement costs. This amount is based on our current estimates of the amounts of expenditures we will be required to make in future years to maintain our depleting reserve base, which we believe to be reasonable. In the future, our estimated reserve replacement expenditures may be more than our actual reserve replacement expenditures, which will reduce the amount of available cash from operating surplus that we would otherwise have available for distribution to unitholders. The amount of estimated reserve replacement expenditures deducted from operating surplus is subject to review and change by the Board of Directors of our general partner at least once a year, subject to approval by the conflicts committee of the Board of Directors of our general partner (the “Conflicts Committee”).
An inability to acquire replacement coal reserves could adversely affect our ability to produce coal.
Our business, financial condition and results of operations depend substantially on obtaining coal reserves that have geological characteristics that enable them to be mined at competitive costs and to meet the coal quality needed by our customers. Because we deplete our reserves as we mine coal, our future success and growth will depend, in part, upon our ability
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to acquire additional coal reserves that are economically recoverable. 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. If we fail to acquire or develop additional reserves, our existing reserves will eventually be depleted. Replacement reserves may not be available when required or, if available, may not be capable of being mined at costs comparable to those characteristic of the depleting mines. Exhaustion of reserves at particular mines with certain valuable coal characteristics also may have an adverse effect on our operating results that is disproportionate to the percentage of overall production represented by such mines. Our ability to obtain other reserves could be limited by restrictions under our existing credit facilities or future debt agreements. Our inability to obtain reserves could adversely affect our business, financial condition and/or results of operations.
Because most of the coal in the vicinity of our Kemmerer mine is owned by the U.S. federal government, our future success and growth would be affected if we are unable to acquire or are significantly delayed in the acquisition of additional reserves through the federal competitive leasing process.
The U.S. federal government owns most of the coal in the vicinity of our mines. Accordingly, the federal competitive leasing process, which is administered by the Bureau of Land Management (“BLM”), is our primary means of acquiring additional reserves. In order to win a lease and acquire additional coal, our bid for a coal tract must meet or exceed the fair market value of the coal based on the internal estimates of the BLM, which are not published, and must also exceed any other third-party bids. The BLM, however, is not required to grant a lease even if it determines that a bid meets or exceeds the fair market value estimate. Furthermore, since multiple parties are permitted to submit bids for any such federal lease, another bid may be accepted instead of our own. Over time, federal coal leases have become increasingly more competitive and expensive to obtain, and the review process to act on a lease for bid continues to lengthen. We expect this trend to continue. Any failure or delay in acquiring a coal lease, or the inability to do so on economically viable terms, could cause our production to decline, and may adversely affect our business, cash flows and results of operations, perhaps materially. In January 2016, the U.S. Department of the Interior Secretary Jewell issued an order calling for a comprehensive programmatic review under the National Environmental Policy Act of the federal coal program to ensure that the program prices the leases appropriately and takes into account impacts on the environment and public health. The Department has suspended all new coal leasing decisions pending completion of this review. The programmatic review does not affect coal reserves currently under lease. The review will look closely at how, when and where leases will occur. The review is anticipated to take at least three years to complete.
The leasing process also requires us to acquire rights to mine from certain surface owners overlying the coal before the federal government will agree to lease the coal. Surface rights are becoming increasingly more difficult and costly to acquire. Certain federal regulations provide a specific class of surface owners, also known as qualified surface owners (‘‘QSOs’’), with the ability to prohibit the BLM from leasing its coal. If a QSO owns the land overlying a coal tract, federal laws prohibit us from leasing the coal tract without first securing surface rights to the land, or purchasing the surface rights from the QSO. This right of QSOs allows them to exercise significant influence over negotiations to acquire surface rights and can delay the leasing process or ultimately prevent the acquisition of coal underlying their surface rights. If we are unable to successfully negotiate access rights with QSOs at a price and on terms acceptable to us, we may be unable to acquire federal coal leases on land owned by the QSO. Our profitability could be adversely affected, perhaps materially, if the prices to acquire land owned by QSOs increase.
We may not be able to successfully replace our reserves or grow through future acquisitions or organic growth projects.
From time to time, we may seek to expand our operations by adding new mines and reserves through strategic acquisitions or organic growth projects, including drop-downs from our general partner, and we intend to continue expanding our operations and coal reserves through these transactions. Our future growth could be limited if we are unable to continue making acquisitions or conducting organic growth projects, or if we are unable to successfully integrate the companies, businesses or properties we acquire or that are contributed to us from our general partner. We may not be successful in consummating any such transactions and the consequences of undertaking these transactions are unknown. Our ability to conduct these transactions in the future could be limited by restrictions under our existing or future debt agreements, competition from other coal companies for attractive properties, the lack of suitable acquisition candidates, and regulatory restrictions on us or our general partner.
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 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
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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 which include 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 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.
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
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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.
Concerns regarding climate change are, in many of the jurisdictions in which we operate, leading to increasing interest and in some cases enactment of, laws and regulations governing greenhouse gas emissions, which affect the end-users of coal and could reduce the demand for coal as a fuel source and cause the volume of our sales and/or the prices we receive to decline. These laws and regulations also have imposed, and will continue to impose, costs directly on us.
GHG emissions have increasingly become the subject of international, national, state, provincial and local attention. Coal-fired power plants can generate large amounts of GHG emissions. Accordingly, legislation or regulation intended to limit GHGs will likely indirectly affect our coal operations by limiting our customers’ demand for our products or reducing the prices we can obtain, and also may directly affect our own power operations. In the United States, the EPA, acting under existing provisions of the federal Clean Air Act has promulgated GHG-related reporting and permitting rules. Portions of the EPA’s GHG permitting rules, which were the subject of litigation by some industry groups and states, were struck down in part by the U.S. Supreme Court, but the EPA’s authority to impose GHG control technologies on a majority of large emissions sources, including coal-fired electric utilities, remain in place. In furtherance of President Obama’s Climate Action Plan announced in June 2013, the EPA issued in August 2015 final standards for GHG emissions from existing fossil-fuel fired power plants, as well as new, modified and reconstructed fossil-fuel fired power plants. The Clean Power Plan sets standards for existing sources as stringent state-specific carbon emission rates to be phased in between 2020 and 2030. The rule would give states the discretion to use a variety of approaches - including cap-and-trade programs - to meet the standard. In February of 2016, however, the Supreme Court issued an order staying the Clean Power Plan pending judicial review of the rule by the U.S. Court of Appeals for the D.C. Circuit as well as potential review by the Supreme Court. The D.C. Circuit issued an expedited briefing schedule for challenges to the rule, and an en banc court heard oral argument on September 27, 2016. However, the Trump Administration has indicated that it plans to repeal the rule and it is uncertain whether it will be replaced. The U.S. Congress has considered, and in the future may again consider, legislation governing GHG emission, including “cap and trade” legislation that would establish a cap on emissions of GHGs covering much of the economy in the United States and would require most sources of GHG emissions to obtain GHG emission “allowances” corresponding to their annual emissions of GHGs. In addition, coal-fired power plants, including new coal-fired power plants or capacity expansions of existing plants, have become subject to opposition by environmental groups seeking to curb the environmental effects of GHG emissions. It is difficult to predict at this time the effect these rules would have on our revenues and profitability. See Item 1 - Business - Material Effects of Regulation.
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.
An inability to obtain and/or renew permits necessary for WMLP’s operations could prevent it from mining certain of its coal reserves.
The slowing pace at which permits are issued or renewed for new and existing mines in WMLP’s area of operations has materially impacted production in Appalachia. Section 402 National Pollutant Discharge Elimination System permits and Section 404 CWA permits are required to discharge wastewater and dredged or fill material into waters of the United States. WMLP’s surface coal mining operations typically require such permits to authorize activities such as the creation of sediment ponds and the reconstruction of streams and wetlands impacted by its mining operations. Although the CWA gives the EPA a limited oversight role in the Section 404 permitting program, the EPA has recently asserted its authorities more forcefully to question, delay, and prevent issuance of some Section 404 permits for surface coal mining in Appalachia. Currently, significant uncertainty exists regarding the obtaining of permits under the CWA for coal mining operations in Appalachia due to various initiatives launched by the EPA regarding these permits, including the issuance in May 2015 of a final rule revising the definition of regulated waters and the issuance of the Stream Protection Rule by the OSM in December 2016. An inability to obtain the necessary permits to conduct WMLP’s mining operations or an inability to comply with the requirements of applicable permits could reduce WMLP’s production and cash flows, which could adversely affect its business, financial condition and/or results of operations and our cash flow.
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Our coal mining operations are subject to external conditions that could disrupt operations and negatively affect our results of operations.
Our coal mining operations are all surface mines. These mines are subject to conditions or events beyond our control that could disrupt operations, affect production, and/or 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; competition and/or conflicts with other natural gas resource extraction activities and production within our operating areas; inability to acquire or maintain necessary permits or mining or surface rights; changes in governmental regulation of the mining industry or the electric utility industry; accidental mine water flooding; labor-related interruptions; transportation delays in barge, rail and truck systems due to weather-related problems, mechanical difficulties, strikes, bottlenecks, and other events; mining and processing equipment unavailability and failures and unexpected maintenance problems; potential unionization of our workforce; and accidents, including fire and explosions from methane. Major disruptions in operations at any of our mines over a lengthy period could adversely affect the profitability of our mines. Any of these conditions may increase the cost of mining and delay or halt production at particular mines for varying lengths of time, which in turn could adversely affect our business, financial condition and/or results of operations.
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 due to selling fewer tons of coal. We maintain business interruption insurance coverage 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.
In general, mining accidents present a risk of various potential liabilities depending on the nature of the accident, the location, the proximity of employees or other persons to the accident scene and a range of other factors. Possible liabilities arising from a mining accident include workers’ compensation claims or civil lawsuits for workplace injuries, claims for personal injury or property damage by people living or working nearby, and fines and penalties including possible criminal enforcement against us and certain of our employees. In addition, a significant accident that results in a mine shutdown could give rise to liabilities for failure to meet the requirements of coal-supply agreements, especially if the counterparties dispute our invocation of the force majeure provisions of those agreements. We maintain insurance coverage to mitigate the risks of certain of these liabilities, but those policies are subject to various exclusions and limitations. We cannot assure you that we will receive coverage under those policies for any personal injury, or property damage that may arise out of such an accident. Currently, we do not carry business interruption insurance and we may not carry other types of insurance in the future. Moreover, certain potential liabilities, such as fines and penalties, are not insurable risks. Thus, a serious mine accident may result in material liabilities that adversely affect our business, financial condition and/or results of operations.
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.
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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 mines 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 our business, financial condition and/or results of operations.
The assumptions underlying our reclamation and mine closure obligations could be materially inaccurate.
The Federal Surface Mining Control and Reclamation Act of 1977 and counterpart state laws and regulations establish operational, reclamation and closure standards for all aspects of surface mining, as well as most aspects of underground mining. Estimates of our total reclamation and mine closing liabilities are based upon permit requirements and our engineering expertise related to these requirements. While the estimate of our reclamation liability is reviewed regularly by our management, the estimate can change significantly if actual costs vary from assumptions or if governmental regulations change significantly. Such changes could adversely affect our business, financial condition and/or results of operations.
If the assumptions underlying our asset retirement 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 calculate the total estimated asset retirement obligations, or ARO, for final reclamation and mine closure according to the guidance provided by U.S. Generally Accepted Accounting Principles ("GAAP") and current industry practice. Estimates of our total ARO 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.
We estimate that our gross ARO, which is based upon projected mine lives, current mine plans, permit requirements and our experience, was $52.2 million (on a present value basis) at December 31, 2016. We must recover the costs incurred for these liabilities 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. See Item 7 - Management’s Discussion and Analysis of Financial Condition and Results of Operations - Critical Accounting Policies and Estimates - Asset Retirement Obligations, Final Reclamation Costs and Reserve Estimates.
If the cost of obtaining new reclamation bonds and renewing existing reclamation bonds increases or if we are unable to obtain additional bonding capacity, our operating results could be negatively affected.
We are required to provide bonds to secure our obligations to reclaim lands used for mining. We must post a bond before we obtain a permit to mine any new area. These bonds are typically renewable on a yearly basis. Bonding companies are requiring that applicants collateralize increasing portions of their obligations to the bonding company. In 2016, we paid approximately $3.0 million in premiums for reclamation bonds. 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.
Transportation impediments may hinder our current operations or future growth.
We depend upon barge, rail and truck systems to deliver coal to our customers. Disruptions in transportation services due to weather-related problems, mechanical difficulties, strikes, lockouts, bottlenecks, and other events could impair our ability to
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deliver coal to our customers. As we do not have long-term contracts with transportation providers to ensure consistent service, decreased performance levels over long periods of time could cause our customers to look to other sources for their coal needs. In addition, increases in transportation costs, including the price of gasoline and diesel fuel, could make coal a less competitive source of energy when compared to alternative fuels or could make coal produced in one region of the United States less competitive than coal produced in other regions of the United States or abroad. Our inability to timely deliver coal due to rising transportation costs could have a material adverse effect on our business, financial condition and/or results of operations.
The unavailability of rail 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. If transportation is restricted or is unavailable, we may be unable to sell into new markets and, therefore, the lack of rail capacity could hamper our future growth.
It is possible that one or more states in which our coal is transported by truck may modify their laws to further limit truck weight limits. 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 our 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 our ability to increase or to maintain production and could adversely affect our revenues.
Decreased availability or increased costs of key equipment and materials could impact our cost of production and decrease our profitability.
We depend on reliable supplies of mining equipment, replacement parts and materials such as explosives, diesel fuel, tires and magnetite. The supplier base providing mining materials and equipment has been relatively consistent in recent years, although there continues to be consolidation, which has resulted in a limited number of suppliers for certain types of equipment and supplies. Any significant reduction in availability or increase in cost of any mining equipment or key supplies could adversely affect our operations and increase our costs, which could adversely affect our operating results and cash flows.
In addition, the prices we pay for these materials are strongly influenced by the global commodities market. Coal mines consume large quantities of commodities such as steel, copper, rubber products, explosives, diesel and other liquid fuels. 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.
We enter into forward-purchase contract arrangements for a portion of our anticipated diesel fuel and explosive needs. Additionally, some of our expected diesel fuel requirements are protected, in varying amounts, by diesel fuel escalation provisions contained in coal supply contracts with some of our 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 our strategy provides us protection in the event of price increases to our diesel fuel, it may also prevent us from the benefits of price decreases. If prices for diesel fuel decreased significantly below our forward-purchase contracts, we would lose the benefit of any such decrease.
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.
The Kemmerer Drop (as defined in Note 1. Organization And Presentation to the consolidated financial statements) added unionized employees to our workforce, and our workforce may become further unionized in the future.
Approximately 236 of Kemmerer’s 297 employees who joined our workforce in connection with the Kemmerer Drop are union employees represented by United Mine Workers of America (“UMWA”), and additional members of our workforce may become represented by unions in the future. Although the Kemmerer employees are employed at the WCC level, the exposure to unionized labor in our workforce nonetheless presents an increased risk of strikes and other labor disputes, and our ability to alter labor costs will be subject to collective bargaining, which could adversely affect stability of production and our results of operations. While the occurrence of labor strikes are generally deemed force majeure events under Kemmerer’s long-term coal
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supply agreements, which would thereby exempt the mine from its delivery obligations, the loss of revenue from the Kemmerer mine caused by a labor strike for even a short time could have a material adverse effect on our financial results, cash flows and ability to make distributions to our unitholders.
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. Increased unionization of our mines may adversely affect our business, financial condition and/or 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. 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 federal and state 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 any 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 any closed mines. These actions could adversely affect our business, financial condition and/or results of operations.
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New legislation or regulations and orders may be adopted that may materially adversely affect our mining operations, our cost structure and/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 and/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/or results of operations. For more information, see Item 1 - Business - Material Effects of Regulation.
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. More recently, the new United States Administration and members of the U.S. Congress have stated that they will seek to modify, repeal, or otherwise invalidate all, or certain provisions of, the PPACA. On January 20, 2017, President Trump signed an executive order stating that it is the policy of his Administration to seek the prompt repeal of the PPACA and directed executive departments and federal agencies to waive, defer, grant exemptions from, or delay the implementation of the provisions of the PPACA to the maximum extent permitted by law. Additionally, the U.S. House and Senate recently passed a budget resolution that authorizes congressional committees to draft legislation to repeal all or portions of the PPACA and permits such legislation to pass with a majority vote in the Senate. We will continue to evaluate the impact and status of the PPACA in future periods.
Mining operations are subject to extensive and costly environmental laws and regulations, and such current and future laws and regulations could materially increase our operating costs or limit our ability to produce and sell coal.
The coal mining industry is subject to numerous and extensive federal, state and local environmental laws and regulations, including laws and regulations pertaining to permitting and licensing requirements, air quality standards, plant and wildlife protection, reclamation and restoration of mining properties, the discharge of materials into the environment, the storage, treatment and disposal of wastes, protection of wetlands, surface subsidence from underground mining, and the effects that mining has on groundwater quality and availability. The costs, liabilities and requirements associated with these laws and regulations are significant, time-consuming and may delay commencement or continuation of our operations.
The possibility exists that new laws or regulations (or new judicial interpretations or enforcement of existing laws and regulations) could materially affect our mining operations and our business, financial condition and/or results of operations, either through direct impacts such as those regulating our existing mining operations, or indirect impacts such as those that discourage or limit our customers' use of coal. For example, the EPA and the U.S. Army Corps of Engineers have issued a final rule to clarify which waters and wetlands are subject to regulation under the CWA. The implementation of the rule was stayed nationwide in October 2015. A change in CWA jurisdiction and permitting requirements could increase or decrease our permitting and compliance costs. Additionally, 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. Although we believe that we are in substantial compliance with existing laws and regulations, we may, in the future, experience violations that would subject us to administrative, civil and criminal penalties and a range of other possible sanctions. As a result, the consequences for any noncompliance may become more significant in the future.
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.
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Our customers are subject to extensive environmental regulations particularly with respect to air emissions other than GHG. Coal contains impurities, including but not limited to sulfur, mercury, chlorine and other elements or compounds, many of which are released into the air when coal is burned. The emission of these and other substances is extensively regulated at the federal, state, provincial and local level, and these regulations significantly affect our customers’ ability to use the coal we produce and, therefore, the demand for that coal. The EPA intends to issue or has issued a number of significant regulations that will impose more stringent requirements relating to air, water and waste controls on electric generating units. These rules include the EPA’s final rule for CCR management, announced in December 2014, that further regulates the handling of wastes from the combustion of coal. In April 2014, the U.S. Supreme Court upheld the EPA’s Cross-State Air Pollution Rule, which would require stringent reductions in emissions of nitrogen oxides and sulfur dioxide from power plants in much of the U.S. For more details, see Item 1 - Business - Material Effects of Regulation. In May 2014, the EPA Administrator signed a final rule that establishes requirements for cooling water intake structures for the withdrawal of cooling water by electric generating plants; the rule is anticipated to affect over 500 power plants.
Considerable uncertainty is associated with air emissions initiatives, and it is unclear how the Trump Administration will approach both previous rules and new rulemakings. New regulations are in the process of being developed, and many existing and potential regulatory initiatives are subject to review by federal or state agencies or the courts. Stringent air emissions limitations are already in place, and these limitations will likely require significant emissions control expenditures for many coal-fired power plants. Should the owners of power plants we serve be forced by the EPA to install such technology, the capital requirements could make the continued operation unsustainable. As a result, 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.
Risks Inherent in an Investment in Us
Our partnership agreement limits our general partner’s fiduciary duties to our unitholders and restricts the remedies available to our unitholders for actions taken by our general partner that might otherwise constitute breaches of fiduciary duties.
Fiduciary duties owed to our unitholders by our general partner are prescribed by law and the partnership agreement. The Delaware Revised Uniform Limited Partnership Act (the “Delaware Act”) provides that Delaware limited partnerships may, in their partnership agreements, restrict the fiduciary duties owed by the general partner to limited partners and the partnership. Our partnership agreement contains such provisions. For example, our partnership agreement:
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limits the liability and reduces the fiduciary duties of our general partner, while also restricting the remedies available to our unitholders for actions that, without these limitations, might constitute breaches of fiduciary duty. As a result of purchasing common units, our unitholders consent to some actions and conflicts of interest that might otherwise constitute a breach of fiduciary or other duties under applicable state law;
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permits our general partner to make a number of decisions in its individual capacity, as opposed to in its capacity as our general partner. This entitles our general partner to consider only the interests and factors that it desires, and it has no duty or obligation to give any consideration to any interest of, or factors affecting, us, our affiliates or any limited partner. Examples include the exercise of its limited call right, its voting rights with respect to the units it owns, its registration rights and its determination whether or not to consent to any merger or consolidation of the partnership;
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provides that our general partner shall not have any liability to us or our unitholders for decisions made in its capacity as general partner so long as it acted in good faith, meaning our general partner believed that the decision was in the best interests of the partnership;
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generally provides that affiliated transactions and resolutions of conflicts of interest not approved by the audit committee of the Board of Directors of our general partner acting as a conflicts committee, and not involving a vote of our unitholders, must be on terms no less favorable to us than those generally being provided to or available from unrelated third parties or be “fair and reasonable” to us and that, in determining whether a transaction or resolution is “fair and reasonable,” our general partner may consider the totality of the relationships between the parties involved, including other transactions that may be particularly advantageous to us; and
WESTMORELAND RESOURCE PARTNERS, LP AND SUBSIDIARIES
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provides that our general partner and its officers and directors will not be liable for monetary damages to us or our limited partners for any acts or omissions unless there has been a final and non-appealable judgment entered by a court of competent jurisdiction determining that our general partner or those other persons acted in bad faith or engaged in fraud or willful misconduct.
By purchasing a common unit, a common unitholder will become bound by the provisions of our partnership agreement, including the provisions described above.
Our general partner and its affiliate may have conflicts of interest with us, and their limited fiduciary duties to our unitholders may permit them to favor their own interests to the detriment of our unitholders.
WCC owns 93.91% beneficial limited partner interest in us on a fully diluted basis at December 31, 2016, as well as 100% of our general partner, which owns all of our outstanding 35,291 general partner units and incentive distribution rights. Although our general partner has certain fiduciary duties to manage us in a manner beneficial to us and our unitholders, the executive officers and directors of our general partner have a fiduciary duty to manage our general partner in a manner beneficial to its owners. Furthermore, since certain executive officers and directors of our general partner are executive officers or directors of affiliates of our general partner, conflicts of interest may arise between WCC and its affiliates, including our general partner, on the one hand, and us and our unitholders, on the other hand. As a result of these conflicts, our general partner may favor its own interests and the interests of its affiliates over the interests of our unitholders. The risk to our unitholders due to such conflicts may arise because of the following factors, among others:
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our general partner is allowed to take into account the interests of parties other than us, such as WCC, in resolving conflicts of interest, which has the effect of limiting its fiduciary duty to our unitholders;
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neither our partnership agreement nor any other agreement requires owners of our general partner to pursue a business strategy that favors us. Executive officers and directors of our general partner’s owners have a fiduciary duty to make these decisions in the best interest of their owners, which may be contrary to our interests;
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our general partner determines the amount and timing of asset purchases and sales, capital expenditures, borrowings and issuances of additional partnership securities and reserves, each of which can affect our financial condition;
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our general partner determines which costs incurred by it and its affiliates are reimbursable by us;
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our partnership agreement does not restrict our general partner from causing us to pay it or its affiliates for any services rendered on terms that are fair and reasonable to us or entering into additional contractual arrangements with any of these entities on our behalf;
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our general partner intends to limit its liability regarding our contractual and other obligations;
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our general partner may exercise its limited right to call and purchase common units if it and its affiliates own more than 80% of the common units which could cause unitholders to sell units at a time and price that may not be desirable;
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our general partner controls the enforcement of obligations owed to us by it and its affiliates; and
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our general partner decides whether to retain separate counsel, accountants or others to perform services for us.
In addition, WCC currently maintains consolidated interests in other companies in the energy and natural resource sectors. Our partnership agreement provides that our general partner will be restricted from engaging in any business activities other than acting as our general partner and those activities incidental to its ownership interest in us. However, WCC is not prohibited from engaging in other businesses or activities, including those that might be in direct competition with us. As a result, WCC could potentially compete with us for acquisition opportunities and for new business or extensions of the existing services provided by us.
Pursuant to the terms of our partnership agreement, the doctrine of corporate opportunity, or any analogous doctrine, does not apply to our general partner or any of its affiliates, including its executive officers, directors and owners. Any such person or entity that becomes aware of a potential transaction, agreement, arrangement or other matter that may be an opportunity for us will not have any duty to communicate or offer such opportunity to us. Any such person or entity will not be liable to us or to any limited partner for breach of any fiduciary duty or other duty by reason of the fact that such person or entity pursues or
WESTMORELAND RESOURCE PARTNERS, LP AND SUBSIDIARIES
acquires such opportunity for itself, directs such opportunity to another person or entity or does not communicate such opportunity or information to us. This may create actual and potential conflicts of interest between us and affiliates of our general partner and result in less than favorable treatment of us and our unitholders.
For more information, please read the above risk titled "Our partnership agreement limits our general partner’s fiduciary duties to our unitholders and restricts the remedies available to our unitholders for actions taken by our general partner that might otherwise constitute breaches of fiduciary duties."
Our unitholders have limited voting rights, are not entitled to elect our general partner or its directors and have limited ability to remove our general partner without its consent.
Unlike the holders of common stock in a corporation, our unitholders have only limited voting rights on matters affecting our business and, therefore, limited ability to influence management’s decisions regarding our business. Our unitholders have no right to elect our general partner or its Board of Directors on an annual or other continuing basis. The Board of Directors of our general partner is chosen entirely by its members and not by our unitholders. Furthermore, if our unitholders are dissatisfied with the performance of our general partner, they have limited ability to remove our general partner.
Our unitholders are unable to remove our general partner without its consent because affiliates of our general partner own sufficient units to be able to prevent removal of our general partner. The vote of the holders of at least 80% of all outstanding common units is required to remove our general partner. Our general partner owns 0.16% of our common units and the owner of our general partner, WCC, owns 93.91% beneficial limited partner interest on a fully diluted basis at December 31, 2016.
Cause is narrowly defined in our partnership agreement to mean that a court of competent jurisdiction has entered a final, non-appealable judgment finding our general partner liable for actual fraud or willful misconduct in its capacity as our general partner. Cause does not include most cases of charges of poor management of the business, so the removal of our general partner during the subordination period because of our unitholders’ dissatisfaction with our general partner’s performance in managing our partnership will most likely result in the termination of the subordination period.
The control of our general partner may be transferred to a third party without unitholder consent.
Our general partner may transfer its general partner interest in us to a third party in a merger or in a sale of all or substantially all of its assets without the consent of our unitholders. Furthermore, there is no restriction in our partnership agreement on the ability of the members of our general partner to transfer their respective membership interests in our general partner to a third party. The new members of our general partner would then be in a position to replace the Board of Directors and executive officers of our general partner with their own choices and to control the decisions and actions of the Board of Directors and executive officers of our general partner.
The incentive distribution rights of our general partner may be transferred to a third party without unitholder consent.
Our general partner may transfer its incentive distribution rights to a third party at any time without the consent of our unitholders. If our general partner transfers its incentive distribution rights to a third party but retains its general partner interest, our general partner may not have the same incentive to grow our partnership and increase quarterly distributions to unitholders over time as it would if it had retained ownership of its incentive distribution rights.
Our general partner has a limited call right that may require our unitholders to sell their common units at an undesirable time or price.
At any time that our general partner and its affiliates own more than 80% of the common units, our general partner will have the right, but not the obligation, which it may assign to any of its affiliates or to us, to acquire all, but not less than all, of the common units held by unaffiliated persons at a price not less than the then-current market price. As a result, our unitholders may be required to sell their common units at an undesirable time or price and may not receive any return on their investment. Our unitholders may also incur a tax liability upon a sale of their common units. Our general partner is not obligated to obtain a fairness opinion regarding the value of the common units to be repurchased by it upon exercise of the limited call right. There is no restriction in our partnership agreement that prevents our general partner from issuing additional common units and exercising its limited call right. If our general partner exercised its limited call right, the effect would be to take us private and, if the common units were subsequently deregistered, we would no longer be subject to the reporting requirements of the Securities Exchange Act of 1934, as amended (the “Exchange Act”).
WESTMORELAND RESOURCE PARTNERS, LP AND SUBSIDIARIES
We may issue additional units without unitholder approval.
At any time, we may issue an unlimited number of limited partner interests of any type without the approval of our unitholders. Further, our partnership agreement does not prohibit the issuance of equity securities that may effectively rank senior to our common units. The issuance by us of additional common units or other equity securities of equal or senior rank will have the following effects:
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our unitholders’ proportionate ownership interest in us will decrease;
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the amount of cash available for distribution on each unit may decrease;
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the relative voting strength of each previously outstanding unit may be diminished; and
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the market price of the common units may decline.
Our general partner may, without unitholder approval, elect to cause us to issue common units and general partner units to it in connection with a resetting of the target distribution levels related to its incentive distribution rights.
Our general partner has the right, at any time when it has received distributions on its incentive distribution rights at the highest level to which it is entitled (48.0%) for each of the prior four consecutive fiscal quarters, to reset the initial target distribution levels at higher levels based on our distributions at the time of the exercise of the reset election. Following a reset election by our general partner, the minimum quarterly distribution will be adjusted to equal the reset minimum quarterly distribution and the target distribution levels will be reset to correspondingly higher levels based on percentage increases above the reset minimum quarterly distribution.
If our general partner elects to reset the target distribution levels, it will be entitled to receive a number of common units and general partner units. The number of common units to be issued to our general partner will be equal to that number of common units that would have entitled their holder to an average aggregate quarterly cash distribution in the prior two quarters equal to the average of the distributions to our general partner on the incentive distribution rights in the prior two quarters. Our general partner will be issued the number of general partner units necessary to maintain our general partner’s interest in us that existed immediately prior to the reset election. We anticipate that our general partner would exercise this reset right in order to facilitate acquisitions or internal growth projects that would not be sufficiently accretive to cash distributions per common unit without such conversion. It is possible, however, that our general partner could exercise this reset election at a time when it is experiencing, or expects to experience, declines in the cash distributions it receives related to its incentive distribution rights and may, therefore, desire to be issued common units rather than retain the right to receive distributions on its incentive distribution rights based on the initial target distribution levels. As a result, a reset election may cause our common unitholders to experience a reduction in the amount of cash distributions that our common unitholders would have otherwise received had we not issued new common units and general partner units to our general partner in connection with resetting the target distribution levels.
The market price of our common units could be impacted by sales of substantial amounts of our common units in the public markets, including sales by our existing unitholders.
A unitholder may sell some or all of our common units that it owns or it may distribute our common units to the holders of its equity interests and those holders may dispose of some or all of these units. The sale or disposition of a substantial number of our common units in the public markets could have a material adverse effect on the price of our common units or could impair our ability to obtain capital through an offering of equity securities. We do not know whether any such sales would be made in the public market or in private placements, nor do we know what impact such potential or actual sales would have on our unit price in the future.
An increase in interest rates may cause the market price of our common units to decline.
Like all equity investments, an investment in our common units is subject to certain risks. In exchange for accepting these risks, investors may expect to receive a higher rate of return than would otherwise be obtainable from lower-risk investments. Accordingly, as interest rates rise, the ability of investors to obtain higher risk-adjusted rates of return by purchasing government-backed debt securities may cause a corresponding decline in demand for riskier investments generally, including yield-based equity investments such as publicly-traded limited partnership interests. Reduced demand for our common units resulting from investors seeking other more favorable investment opportunities may cause the trading price of our common units to decline.
WESTMORELAND RESOURCE PARTNERS, LP AND SUBSIDIARIES
We must pay fees to and reimburse our general partner and its affiliates for services provided, which will reduce our cash available for distributions.
Under the Services Agreement, our general partner will continue providing administrative, engineering, operating and other services to the Partnership for a fixed annual fee of $2.2 million in 2017 for certain administrative services plus reimbursement at cost for other expenses and expenditures. The term of the Agreement expires on December 31 of each calendar year end, and automatically renews for successive one-year periods unless terminated. The reimbursement to our general partner for such expenses will be determined by our general partner in accordance with the terms of our partnership agreement and as provided under the Services Agreement. In determining the costs and expenses allocable to us, our general partner is subject to its fiduciary duty, as modified by our partnership agreement, to the limited partners, which requires it to act in good faith. These expenses include all costs incurred by our general partner and its affiliates in managing and operating us. We are managed and operated by executive officers and directors of our general partner. The reimbursement of expenses and payment of fees, if any, to our general partner and its affiliates will reduce our cash available for distributions.
Our unitholders may have liability to repay distributions.
Under certain circumstances, our unitholders may have to repay amounts wrongfully returned or distributed to them. Under Section 17-607 of the Delaware Act, we may not make a distribution to our unitholders if the distribution would cause our liabilities to exceed the fair value of our assets. Delaware law provides that, for a period of three years from the date of the impermissible distribution, limited partners who received the distribution and who knew at the time of the distribution that it violated Delaware law will be liable to the limited partnership for the distribution amount. Purchasers of units who become limited partners are liable for the obligations of the transferring limited partner to make contributions to the partnership that are known to the purchaser of units at the time it became a limited partner and for unknown obligations if the liabilities could be determined from our partnership agreement. Liabilities to partners on account of their partnership interests and liabilities that are non-recourse to the partnership are not counted for purposes of determining whether a distribution is permitted.
Common units held by unitholders who are not eligible citizens will be subject to redemption.
Our general partner may require each limited partner to furnish information about his nationality, citizenship or related status. If a limited partner fails to furnish information about his nationality, citizenship or other related status within 30 days after a request for the information or our general partner determines after receipt of the information that the limited partner is not an eligible citizen, the limited partner may be treated as a non-citizen assignee. A non-citizen assignee does not have the right to direct the voting of his units and may not receive distributions in kind upon our liquidation. Furthermore, we have the right to redeem all of the common units of any holder that is not an eligible citizen or fails to furnish the requested information. The redemption price will be paid in cash or by delivery of a promissory note, as determined by our general partner.
Tax Risks to Common Unitholders
Our tax treatment depends on our status as a partnership for federal income tax purposes, as well as our being subject to minimal entity-level taxation by individual states. If the Internal Revenue Service, or IRS, were to treat us as a corporation for federal income tax purposes, or we become subject to a material amount of entity-level taxation for state tax purposes, it would substantially reduce the amount of cash available for distribution to our unitholders.
The anticipated after-tax economic benefit of an investment in our common units depends largely on our being treated as a partnership for federal income tax purposes. We have not requested, and do not plan to request, a ruling from the IRS on this or any other tax matter affecting us.
Despite the fact that we are a limited partnership under Delaware law, it is possible in certain circumstances for a partnership such as ours to be treated as a corporation for federal income tax purposes. Although we do not believe based upon our current operations that we will be treated as a corporation, the IRS could disagree with the positions we take or a change in our business or a change in current law could cause us to be treated as a corporation for federal income tax purposes or otherwise subject us to taxation as an entity.
If we were treated as a corporation for federal income tax purposes, we would pay federal income tax on our taxable income at the corporate tax rate, which is currently a maximum of 35%, and would likely pay state and local income tax at varying rates. Distributions to a unitholder would generally be taxed again as corporate dividends (to the extent of our current and accumulated earnings and profits), and no income, gains, losses, deductions, or credits would flow through to the unitholder. Because a tax would be imposed upon us as a corporation, our cash available for distribution to a unitholder would be
WESTMORELAND RESOURCE PARTNERS, LP AND SUBSIDIARIES
substantially reduced. Therefore, if we were treated as a corporation for federal tax purposes there could be a material reduction in the anticipated cash flow and after-tax return to a unitholder, likely causing a substantial reduction in the value of our common units.
We are subject to extensive tax laws and regulations, with respect to federal, state and foreign income taxes and transactional taxes such as excise, sales/use, payroll, franchise and ad valorem taxes. New tax laws and regulations and changes in existing tax laws and regulations are continuously being enacted that could result in increased tax expenditures in the future. Further, changes in current state law may subject us to additional entity-level taxation by individual states. Because of widespread state budget deficits and other reasons, several states are evaluating ways to subject partnerships to entity-level taxation through the imposition of state income, franchise and other forms of taxation. Imposition of any such taxes could adversely affect our cash available for distribution to unitholders.
Our partnership agreement provides that, if a law is enacted or existing law is modified or interpreted in a manner that subjects us to taxation as a corporation or otherwise subjects us to entity-level taxation for federal, state or local income tax purposes, the minimum quarterly distribution amount and the target distribution amounts will be adjusted to reflect the impact of that law on us.
The tax treatment of publicly traded partnerships or an investment in our common units could be subject to potential legislative, judicial or administrative changes and differing interpretations, possibly on a retroactive basis.
The present federal income tax treatment of publicly traded partnerships, including us, or an investment in our common units may be modified by administrative, legislative or judicial interpretation at any time. Any modification to the federal income tax laws and interpretations thereof may or may not be applied retroactively. Moreover, any such modification could make it more difficult or impossible for us to meet the exception that allows publicly traded partnerships that generate qualifying income to be treated as partnerships (rather than corporations) for federal income tax purposes, affect or cause us to change our business activities, or affect the tax consequences of an investment in our common units. For example, from time to time, members of the U.S. Congress have considered substantive changes to the existing federal income tax laws that would affect the tax treatment of certain publicly traded partnerships. Further, on January 24, 2017, the U.S. Treasury Department (“Treasury”) and the IRS published in the Federal Register final regulations effective as of January 19, 2017 interpreting the scope of activities that generate qualifying income under Section 7704 of the Internal Revenue Code of 1986, as amended (the “Code”). We believe that the income we currently treat as qualifying income satisfies the requirements for qualifying income under the final regulations. We are unable to predict whether any of these changes, or any other proposals, will ultimately be enacted. Any changes could negatively impact the value of an investment in our common units.
Certain federal income tax preferences currently available with respect to coal exploration and development could be eliminated in future legislation.
The passage of any legislation effecting changes in federal income tax laws could eliminate or defer certain tax deductions and other preferences that are currently available with respect to coal exploration and development, and any such change could increase the taxable income allocable to our unitholders or the amount of tax payable on that income and negatively impact the value of an investment in our common units.
If tax authorities contest the tax positions we take, the market for our common units could be adversely impacted, and the cost of any contest with a tax authority would reduce our cash available for distribution to our unitholders.
We have not requested a ruling from the IRS with respect to our treatment as a partnership for federal income tax purposes or any other matter affecting us. Tax authorities may adopt positions that differ from the positions we take, and a tax authority’s positions may ultimately be sustained. It may be necessary to resort to administrative or court proceedings to sustain some or all of the positions we take. A court may not agree with some or all of the positions we take. Any contest with a tax authority, and the outcome of any such contest, may increase a unitholder’s tax liability and result in adjustment to items unrelated to us and could materially and adversely impact the market for our common units and the price at which they trade. The rights of a unitholder owning less than a 1% profits interest in us to participate in the current federal income tax audit process are very limited. In addition, our costs of any contest with any tax authority will be borne indirectly by our unitholders and our general partner because such costs will reduce our cash available for distribution.
Recently enacted legislation, and proposed but withdrawn Treasury regulations, applicable to us for taxable years beginning after December 31, 2017 alters the procedures for auditing large partnerships and also alters the procedures for assessing and collecting taxes due (including applicable penalties and interest) as a result of an audit. Unless we are eligible to
WESTMORELAND RESOURCE PARTNERS, LP AND SUBSIDIARIES
(and choose to) elect to issue revised Schedules K-1 to our partners with respect to an audited and adjusted return, the IRS (and some states) may assess and collect taxes (including any applicable penalties and interest) directly from us in the year in which the audit is completed under the new rules. There can be no assurance that such election will be practical, permissible or effective in all circumstances. If we are required to pay taxes, penalties and interest as the result of audit adjustments, cash available for distribution to our unitholders may be substantially reduced. In addition, because payment would be due for the taxable year in which the audit is completed, unitholders during that taxable year would bear the expense of the adjustment even if they were not unitholders during the audited taxable year.
Our unitholders may be required to pay taxes on income from us even if the unitholders do not receive any cash distributions from us.
Because a unitholder is treated as a partner to whom we allocate taxable income which could be different in amount than the cash we distribute, a unitholder’s allocable share of our taxable income is taxable to it, which may require the payment of federal income taxes and, in some cases, state and local income taxes on its share of our taxable income even if it receives no cash distributions from us. Our unitholders may not receive cash distributions from us equal to their share of our taxable income or even equal to the tax liability that results from that income.
Certain actions that we may take, such as issuing additional units, may increase the federal income tax liability of unitholders.
In the event we issue additional units or engage in certain other transactions in the future, the allocable share of nonrecourse liabilities allocated to the unitholders will be recalculated to take into account our issuance of any additional units. Any reduction in a unitholder’s share of our nonrecourse liabilities will be treated as a distribution of cash to that unitholder and will result in a corresponding tax basis reduction in a unitholder’s units. A deemed cash distribution may, under certain circumstances, result in the recognition of taxable gain by a unitholder, to the extent that the deemed cash distribution exceeds such unitholder’s tax basis in its units.
In addition, the federal income tax liability of a unitholder could be increased if we dispose of assets or make a future offering of units and use the proceeds in a manner that does not produce substantial additional deductions, such as to repay indebtedness currently outstanding or to acquire property that is not eligible for depreciation or amortization for federal income tax purposes or that is depreciable or amortizable at a rate significantly slower than the rate currently applicable to the our assets.
Tax gain or loss on the disposition of common units could be more or less than expected.
If a unitholder sells its common units, the unitholder will recognize a gain or loss equal to the difference between the amount realized and the unitholder’s tax basis in those common units. Because distributions to a unitholder in excess of the total net taxable income allocated to it for a common unit decreases its tax basis in that common unit, the amount, if any, of such prior excess distributions with respect to the units sold will, in effect, become taxable income to the unitholder if the common unit is sold at a price greater than its tax basis in that common unit, even if the price is less than the original cost. Furthermore, a substantial portion of the amount realized, whether or not representing gain, may be taxed as ordinary income due to potential recapture items, including depreciation recapture. In addition, because the amount realized includes a unitholder’s share of our nonrecourse liabilities, if a unitholder sells its common units, the unitholder may incur a tax liability in excess of the amount of cash the unitholder receives from the sale.
Tax-exempt entities and non-U.S. persons face unique tax issues from owning common units that may result in adverse tax consequences to them.
Investment in common units by tax-exempt entities, such as individual retirement accounts, or IRAs, other retirement plans and non-U.S. persons raises issues unique to them. For example, virtually all of our income allocated to organizations that are exempt from federal income tax, including IRAs and other retirement plans, will be unrelated business taxable income, which may be taxable to them. Distributions to non-U.S. persons will be reduced by withholding taxes at the highest applicable effective tax rate, and non-U.S. persons will be required to file federal tax returns and pay tax on their share of our taxable income. If a unitholder is a tax-exempt entity or a non-U.S. person, the unitholder should consult its tax advisor before investing in our common units.
We treat each purchaser of our common units as having the same tax benefits without regard to the actual common units purchased. The IRS may challenge this treatment, which could adversely affect the value of common units.
WESTMORELAND RESOURCE PARTNERS, LP AND SUBSIDIARIES
Because we cannot match transferors and transferees of common units and because of other reasons, we have adopted depreciation and amortization positions that may not conform to all aspects of existing Treasury Regulations. A successful IRS challenge to those positions could adversely affect the amount of tax benefits available to the unitholders. It also could affect the timing of these tax benefits or the amount of gain from the sale of common units and could have a negative impact on the value of common units or result in audit adjustments to unitholders’ tax returns.
We prorate our items of income, gain, loss and deduction between transferors and transferees of our units each month based upon the ownership of our units on the first day of each month, instead of on the basis of the date a particular unit is transferred. The IRS may challenge this treatment, which could change the allocation of items of income, gain, loss and deduction among unitholders.
We prorate our items of income, gain, loss and deduction between transferors and transferees of our units each month based upon the ownership of our units on the first day of each month, instead of on the basis of the date a particular unit is transferred. Treasury and the IRS recently adopted final regulations that provide a safe harbor pursuant to which publicly traded partnerships may use a similar monthly simplifying convention to allocate tax items among transferor and transferee unitholders. However, the regulations do not specifically authorize all aspects of the proration method we have currently adopted. If the IRS were to successfully challenge our proration method, we may be required to change the allocation of items of income, gain, loss and deduction among our unitholders.
A unitholder whose common units are loaned to a “short seller” to cover a short sale of common units may be considered as having disposed of those common units. If so, the unitholder would no longer be treated for tax purposes as a partner with respect to those units during the period of the loan and may recognize gain or loss from the disposition.
Because a unitholder whose common units are loaned to a “short seller” to cover a short sale of common units may be considered as having disposed of the loaned common units, the unitholder may no longer be treated for tax purposes as a partner with respect to those common units during the period of the loan to the short seller and the unitholder may recognize gain or loss from such disposition. Moreover, during the period of the loan to the short seller, any of our income, gain, loss or deduction with respect to those common units may not be reportable by the unitholder and any cash distributions received by the unitholder as to those common units could be fully taxable as ordinary income. Unitholders desiring to assure their status as partners and avoid the risk of gain recognition from a loan to a short seller are urged to modify any applicable brokerage account agreements to prohibit their brokers from borrowing and lending their common units.
We have adopted certain valuation methodologies that may result in a shift of income, gain, loss and deduction between our general partner and the unitholders. The IRS may challenge this treatment, which could adversely affect the value of the common units.
When we issue additional common units or engage in certain other transactions, we determine the fair value of our assets and allocate any unrealized gain or loss attributable to our assets to the capital accounts of our unitholders and our general partner. Our methodology may be viewed as understating the value of our assets. In that case, there may be a shift of income, gain, loss and deduction between certain unitholders and our general partner, which may be unfavorable to such unitholders. Moreover, subsequent purchasers of common units may have a greater portion of their Code Section 743(b) adjustment allocated to our tangible assets and a lesser portion allocated to our intangible assets. The IRS may challenge our valuation methods, or our allocation of the Code Section 743(b) adjustment attributable to our tangible and intangible assets, and allocations of income, gain, loss and deduction between our general partner and certain of the unitholders.
A successful IRS challenge to these methods or allocations could adversely affect the amount of taxable income or loss being allocated to our unitholders. It also could affect the amount of gain from our unitholders’ sale of common units and could have a negative impact on the value of the common units or result in audit adjustments to our unitholders’ tax returns without the benefit of additional deductions.
The sale or exchange of 50% or more of our capital and profits interests during any twelve-month period will result in the termination of our partnership for federal income tax purposes.
We will be considered to have terminated as a partnership for federal income tax purposes if there is a sale or exchange of 50% or more of the total interests in our capital and profits within a twelve-month period. Our termination, among other things, would result in the closing of our taxable year for all unitholders, which would result in us filing two tax returns (and our unitholders could receive two Schedule K-1's if relief from the IRS was not granted, as described below) for one calendar year. Our termination could also result in a significant deferral of depreciation deductions allowable in computing our taxable income.
WESTMORELAND RESOURCE PARTNERS, LP AND SUBSIDIARIES
In the case of a unitholder reporting on a taxable year other than a calendar year, the closing of our taxable year may result in more than twelve months of our taxable income or loss being includable in its taxable income for the year of termination. Under current law, such a termination would not affect our classification as a partnership for federal income tax purposes, but instead, after our termination, we would be treated as a new partnership for tax purposes. If treated as a new partnership, we must make new tax elections and could be subject to penalties if we are unable to determine that a termination occurred. The IRS has announced a relief procedure for publicly traded partnerships that terminate in this manner, whereby if a publicly traded partnership that has terminated requests and the IRS grants special relief, among other things, we will only have to provide one Schedule K-1 to unitholders for the year, notwithstanding two partnership tax years resulting from the termination.
Unitholders may be subject to state and local taxes and return filing requirements in states and localities where they do not reside or own properties.
In addition to federal income taxes, unitholders may be subject to other taxes, including foreign, state and local taxes, unincorporated business taxes and estate, inheritance or intangible taxes that are imposed by the various jurisdictions in which we do business or own property now or in the future, even if the unitholders do not live in any of those jurisdictions. Unitholders may be required to file foreign, state and local income tax returns and pay state and local income taxes in some or all of these jurisdictions. Further, unitholders may be subject to penalties for failure to comply with those requirements. As we make acquisitions or expand our business, we may own assets or do business in additional states that impose a personal income tax or an entity level tax. It is each unitholder’s responsibility to file all federal, foreign, state and local tax returns. Our counsel has not rendered an opinion on the state, local or non-U.S. tax consequences of an investment in common units.
Some of the states in which we do business or own property may require us to, or we may elect to, withhold a percentage of income from amounts to be distributed to a unitholder who is not a resident of the state. Withholding, the amount of which may be greater or less than a particular unitholder’s income tax liability to the state generally, does not relieve the nonresident unitholder from the obligation to file an income tax return. Amounts withheld may be treated as if distributed to unitholders for purposes of determining the amounts distributed by us.
WESTMORELAND RESOURCE PARTNERS, LP AND SUBSIDIARIES
Item 1B.
Item 1B. Unresolved Staff Comments
None.
Item 2.
Item 2. Properties
See Item 1 - Business - Properties for specific information about our mining operations, 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. See Note 21. Commitments And Contingencies to the consolidated financial statements for a description of our pending legal proceedings, which information is incorporated herein by reference.
Item 4.
Item 4. Mine Safety Disclosures
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 Wall Street Reform and Consumer Protection Act and Item 104 of Regulation S-K, are included as Exhibit 95.1 to this Annual Report on Form 10-K.
WESTMORELAND RESOURCE PARTNERS, LP AND SUBSIDIARIES
PART II
Item 5.
Item 5. Market for Registrant’s Common Equity, Related Unitholder Matters and Issuer Purchases of Equity Securities
The common units of Westmoreland Resource Partners, LP are trading on the NYSE under the symbol "WMLP." On March 10, 2017, the closing market price for our common units was $4.70 per unit. As of this date, we had outstanding 1,284,840 limited partner common units with 10 registered holders of record not including unitholders whose units are held in trust by other entities which makes the actual number of unitholders greater than the number of registered holders of record. We also had 16,215,029 Series A Units, 4,512,500 Series B Units and 35,291 general partner units. In addition, we had outstanding warrants to purchase an aggregate of 166,557 common units. All of the Series A Units, Series B Units and general partner units, for which there is no established public trading market, are held by WCC.
The following table sets forth the range of the daily high and low sales prices for the periods indicated:
Cash Distributions
We distribute 100% of our available cash within 45 days after the end of each quarter to unitholders of record and to our GP, subject to the conditions and limitations within the 2014 Financing Agreement. Available cash is determined at the end of each quarter and is generally defined in the Partnership Agreement as all cash and cash equivalents on hand at the end of each quarter less reserves established by our GP in its reasonable discretion for future cash requirements. These reserves are retained to provide for the conduct of our business, the payment of debt principal and interest and to provide funds for future distributions for any one or more of the next four quarters, and to comply with applicable law. Our available cash may also include, if our GP so determines, all or any portion of the cash on hand on the date of determination of available cash for the quarter resulting from working capital borrowings made subsequent to the end of such quarter.
As quarterly distributions of available cash exceed the target distribution levels established in our partnership agreement, our managing general partner receives distributions based on specified increasing percentages of the available cash that exceeds the target distribution levels. The target distribution levels are based on the amounts of available cash from our operating surplus distributed for a given quarter that exceed the minimum quarterly distribution (“MQD”). Our partnership agreement defines the MQD as $0.1333 per unit ($0.5332 per unit on an annual basis).
Under the quarterly IDR provisions of our partnership agreement, our managing general partner is entitled to receive (i) 13% of quarterly distributions over $0.1533 per unit and up to $0.1667 per unit; (ii) 23% of quarterly distributions over $0.1667 per unit and up to $0.2000 per unit; and (iii) 48% of quarterly distributions over $0.2000 per unit. For the years ended December 31, 2016, 2015 and 2014, we did not allocate to our managing general partner any incentive distributions.
In December 2014, we closed on a new $295 million credit facility that replaced our previous term loan and revolving credit facilities, which new credit facility has customary financial and other covenants, including restrictions on our ability to make distributions. See Item 7 - Management’s Discussion and Analysis of Financial Condition and Results of Operations - Credit Facilities.”
WESTMORELAND RESOURCE PARTNERS, LP AND SUBSIDIARIES
Unregistered Sales of Equity Securities
Series A Convertible Units
In August 2015, 15,251,989 Series A Convertible Units were issued to WCC in consideration for its contribution to us of WKL. The Series A Units have the right to share in distributions from us on a pro-rata basis with the common units. All or any portion of each distribution payable in respect of the Series A Units (the “Series A Convertible Unit Distribution”) may, at our Board of Directors' election, be paid in Series A paid-in-kind Units (“Series A PIK Units”). On January 22, 2016 the Board of Director declared a distribution of 404,562 Series A PIK Units in lieu of a $0.20 cash distribution in respect of Series A Convertible Units. On October 28, 2016 the Board of Director declared a distribution of 276,792 Series A PIK Units in lieu of a $0.1333 cash distribution in respect of Series A Convertible Units.
These transactions were exempt from registration pursuant to Section 4(a)(2) of the Securities Act of 1933, as amended (the 'Securities Act").
Series B Convertible Units
On October 28, 2016, we issued 4,512,500 Series B Convertible Units representing limited partner interests in the Partnership (the “Series B Units”) to WCC in exchange for WCC’s 4,512,500 common units (the “Exchange”). Upon issuance of the Series B Units in the Exchange, WCC’s common units were canceled. These transactions were exempt from registration pursuant to the Securities Act.
Issuer Purchases of Equity Securities
During 2016, we did not make any purchases of our common units and no such purchases were made on our behalf.
Securities Authorized for Issuance Under Equity Compensation Plan
See Item 12 - Security Ownership of Certain Beneficial Owners and Management and Related Unitholder Matters which is incorporated by reference into this Item 5.
Stock Performance Graph
The following performance graph compares the cumulative total stockholder return on our common units for the five-year period December 31, 2011 through December 31, 2016 with (i) the cumulative total return over the same period of the NYSE MKT Composite Index, (ii) the cumulative total return over the same period of the SPDR S&P Metals and Mining Index, and (iii) our current peer group index, which consists of Alliance Resource Partners LP, Cloud Peak Energy, Hallador Energy Co., and Rhino Resource Partners LP. We do not have a former peer group due to that fact that we previously filed under the Smaller Reporting Company status which did not require a stock performance graph section as part of this Annual Report on Form 10-K. However, due to our current filing status of Non-Accelerated Filer, we have included this graph. The graph assumes that:
•
You invested $100 in Westmoreland Resource Partners, LP common units and in each index at the closing price on December 31, 2011;
•
All dividends were reinvested;
•
Annual re-weighting of the peer group indices; and
•
You continued to hold your investment through December 31, 2016.
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 units.
WESTMORELAND RESOURCE PARTNERS, LP AND SUBSIDIARIES
2 2016 Peer Group: Alliance Resource Partners LP, Cloud Peak Energy, Hallador Energy Co., and Rhino Resource Partners LP
3 2015 Peer Group: Not applicable due to filing under the Smaller Reporting Company status for 2015 Form 10-K.
WESTMORELAND RESOURCE PARTNERS, LP AND SUBSIDIARIES
Item 6.
Item 6. Selected Financial and Operating Data
WCC's cost of acquiring our GP has been pushed-down to establish a new accounting basis for us. Accordingly, the accompanying consolidated financial statements are presented for two periods, Predecessor and Successor, which relate to the accounting periods preceding and succeeding the completion of the acquisition. The Predecessor and Successor periods have been separated by a vertical line on the face of the consolidated financial statements to highlight the fact that the financial information for such periods has been prepared under two different historical-cost bases of accounting. The following table presents our selected financial and operating data as of the dates and for the periods indicated and should be read in conjunction with 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 Item 1A - Risk Factors.
Overview
See Item 1 - Business - Overview.
We sell almost all of our coal under multi-year agreements to electric generation companies. These multi-year (along with some spot-less than one year in length) coal contracts oftentimes contain price escalation and adjustment provisions, pursuant to which the price for our coal may be periodically revised in line with broad economic indicators such as the consumer price index, commodity-specific indices such as the PPI-light fuel oils index, and/or changes in our actual costs. For our contracts that are not cost protected in nature, we have exposure to inflation and price risk for supplies used in the normal course of production such as diesel fuel and explosives. We manage these items through strategic sourcing contracts in normal quantities with our suppliers and may use derivatives from time-to-time.
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.
Results of Operations
Items that Affect Comparability of Our Results
For 2016 and each of the prior two years, our results have included items that do not relate directly to ongoing operations. The (income) expense components of these items were as follows (in millions):
Items recorded in 2016:
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We incurred $11.3 million in impairment charges comprised of $8.1 million at the Ohio mines from excess equipment due to mine plan changes and $3.2 million at the Kemmerer mine related to a shovel that was scrapped for parts.
Items recorded in 2015:
•
We incurred $2.6 million in various investment banker and legal costs related to the Kemmerer Drop.
WESTMORELAND RESOURCE PARTNERS, LP AND SUBSIDIARIES
•
We incurred $0.7 million in restructuring costs resulting from the right sizing of the financing and accounting team after the acquisition of our general partner by WCC in December 2014.
Items recorded in 2014 (Successor):
•
We incurred $2.8 million in restructuring costs resulting from termination of the executive team after the acquisition of our general partner by WCC on December 31, 2014.
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We incurred $1.6 million in loss on extinguishment debt related to the payoff of the 2013 Financing Agreement.
Items recorded in 2014 (Predecessor):
•
We incurred $0.1 million in restructuring costs related to the idling of our Illinois Basin operations on December 31, 2013. These charges included professional and legal fees, and transportation costs associated with moving idled equipment to our Ohio mines.
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We incurred a $0.5 million gain on extinguishment of debt resulting from the forgiveness of a note payable.
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We incurred $5.5 million in various investment banker and legal costs associated with WCC's acquisition of our general partner on December 31, 2014.
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We received $17.5 million in litigation settlement proceeds, net of legal expenses, from a former customer compensating us for lost profits on coal sales due to a wrongful termination of a coal supply agreement.
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We incurred $7.0 million in debt refinancing costs related to the 2014 Financing Agreement.
Year Ended December 31, 2016 Compared to December 31, 2015
(1)Adjusted EBITDA , a non-GAAP measure, is defined and reconciled to net loss in Item 6 - Selected Financial and Operating Data.
Revenue decreased primarily as a result of continued pricing softness in Ohio. Whether this decrease persists in future years is dependent upon fluctuations in market demand in the region. Net loss decreased and Adjusted EBITDA increased primarily due to lower fuel and labor costs at our Ohio mines and the impact of cost savings initiatives at our Kemmerer mine which are expected to continue into the future.
Coal and Non-Coal Revenues
Coal sales revenue decreased due to a 7.5% decrease in tons sold which amounted to $28.3 million. This decrease was compounded by a decrease in the average sales price per ton of $0.17 or an aggregate $1.3 million. Non-coal revenues, primarily from limestone sales, non-coal services and other (miscellaneous) revenue decreased due to a $2.6 million decrease in non-coal services due to $2.4 million in non-recurring coal handling and transportation service revenue performed on behalf of a subsidiary of WCC during 2015. Additionally, limestone revenue decreased $1.1 million and other (miscellaneous) revenue decreased $2.1 million due to generating $1.8 million in June 2015 compared to $0.6 million in June 2016 in lost coal fees for granting two respective pipeline right-of-ways to multiple third parties.
WESTMORELAND RESOURCE PARTNERS, LP AND SUBSIDIARIES
Cost and Expenses
Cost of coal revenues decreased primarily due to 0.6 million less tons sold in 2016 than in 2015 which corresponds to a $23.2 million decrease in cost of coal revenues, compounded by a decrease in the cost to produce coal of $2.69 per ton, or an aggregate $21.0 million, for the year ended December 31, 2016. Depreciation, depletion and amortization expense decreased primarily due to a smaller operating fleet as part of our effort to reduce costs. Selling and administrative expenses decreased due to reduced headcount, less reliance on outside services and other cost saving efforts during the twelve months ended December 31, 2016.
Nonoperating Results
* Not meaningful
Interest expense increased due to the $120.0 million in additional debt incurred in connection with the Kemmerer Drop on August 1, 2015. Interest income was stable year over year due to a relatively stable balance of cash on hand upon which interest income is earned. In 2016, we recognized expense from the change in fair value of warrants of $0.3 million which is the increase in value of our units traded on the NYSE during 2016 compared to 2015.
Year Ended December 31, 2015 (Successor) Compared to Period of January 1, 2014 through December 31, 2014 (Predecessor)
1Adjusted EBITDA , a non-GAAP measure, is defined and reconciled to net income (loss) in Item 6 - Selected Financial and Operating Data.
Revenue increased due to the Kemmerer Drop offset by a decrease in the average sale price per ton as is discussed in the Coal and Non-coal Revenues section immediately below. Net loss increased due to the factors of increasing revenue which were more than offset by increases in expenses as is discussed in the Cost of Coal Revenues section below. Adjusted EBITDA increased primarily due to the Kemmerer Drop which added $38.3 million.
WESTMORELAND RESOURCE PARTNERS, LP AND SUBSIDIARIES
Coal and Non-coal Revenues
Coal sales revenue increased due to a 50.6% increase in tons sold which amounted to $149.7 million that was primarily the result of the Kemmerer Drop, partially offset by a $8.27 per ton, or an aggregate $70.3 million, decrease in the average sale price per ton. Non-coal revenues decreased due to other miscellaneous revenue decreasing by $17.7 million due to the receipt of $19.5 million in litigation settlement proceeds from a former customer compensating us for lost profits on coal sales due to a wrongfully terminated coal supply agreement in the predecessor period ended December 31, 2014. The $17.7 million decrease in miscellaneous revenue and $1.8 million decrease in limestone revenue was offset in part by a $1.9 million increase in non-coal services and a $0.6 million increase in oil and gas royalties.
Cost and Expenses
Cost of coal revenues increased due to an increase of 2.9 million in tons sold which increased cost of coal revenues $131.1 million. This increase was offset by a $9.73 per ton decrease in the cost to produce coal, or an aggregate $82.7 million.
Depreciation expense increased due to the August 1, 2015 Kemmerer Drop. Amortization expense was $6.9 million for the year ended December 31, 2015, a $0.4 million decrease from $7.3 million for the year ended December 31, 2014. The decrease was primarily attributable to changes in the amortization for asset retirement costs based on revisions to cost estimates and useful lives. Depletion expense was $8.3 million for the year ended December 31, 2015, a $3.0 million increase from $5.3 million for the year ended December 31, 2014, which was attributable to an increase in the depletion rate per ton.
Selling and administrative expenses decreased as the result of one-time expenses resulting from the WCC transactions which includes $2.0 million in equity-based compensation expense related to change of control provisions for the Original LTIP (defined as the long term incentive plant originally adopted in 2007 in connection with our formation and subsequently amended and restated in July 2010 in connection with our initial public offering) for the predecessor period ended December 31, 2014 and other cost reduction efforts.
WESTMORELAND RESOURCE PARTNERS, LP AND SUBSIDIARIES
Nonoperating Results
Our interest expense increased $3.0 million due to the $120.0 million in additional debt incurred through the Kemmerer Drop on August 1, 2015. Our interest income in 2015 came from an increase in cash on hand. We incurred a $0.5 million gain on debt extinguishment for the predecessor period ended December 31, 2014 related to the forgiveness of a note. We recognized income from the change in fair value of warrants of $1.3 million. The increase is the result of the declining value of our units traded on the NYSE. Net loss attributable to noncontrolling interest relates to the 49% ownership interest in Harrison Resources owned by a subsidiary of Consol Energy through September 30, 2014.
Liquidity and Capital Resources
We had the following liquidity at December 31, 2016 and 2015 :
Our business is capital intensive and requires substantial capital expenditures for, among other things, purchasing, maintaining and upgrading equipment used in developing and mining our coal, and acquiring reserves. Our principal liquidity needs are to finance current operations, replace reserves and fund capital expenditures, including costs of acquisitions from time to time, servicing of our debt and paying cash distributions to our unitholders when we are in a position to do so. Our primary sources of liquidity to meet these needs are cash generated by our operations and the limited remainder of our initial term loan borrowing under the 2014 Financing Agreement. Also, if we are able to sell the remaining excess Illinois Basin equipment, a large-capacity shovel and several smaller pieces of equipment, our liquidity will be enhanced. Additionally, selling our remaining coal reserves and/or facilities related to our Illinois Basin operations would further enhance our liquidity.
Our ability to satisfy our working capital requirements, meet debt service obligations, and fund planned capital expenditures substantially depends upon our future operating performance, which may be affected by prevailing economic conditions in the coal industry. To the extent our future operating cash flow or access to financing sources and the costs thereof are materially different than expected, our future liquidity may be adversely affected. 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.
Credit Facilities
See Note 13. Long-Term Debt to the consolidated financial statements for a description of our debt facilities. From time to time depending on market conditions and available cash, we intend to strategically repurchase our outstanding debt.
WESTMORELAND RESOURCE PARTNERS, LP AND SUBSIDIARIES
Historical Sources and Uses of Cash
The following table reflects cash flows for the years indicated:
1 See Note 3. Acquisition And Pushdown Accounting to the consolidated financial statements.
Year Ended December 31, 2016 Compared to Year Ended December 31, 2015
Cash from operations increased $9.1 million to $41.1 million at December 31, 2016 from $32.0 million at December 31, 2015. The $9.1 million increase resulted from a $2.1 million decrease in net loss combined $7.0 million in favorable non-cash operating activity and $6.7 million favorable changes in working capital offset in part by $6.7 million unfavorable change in asset retirement obligation. The $7.0 million favorable change in non-chase operating activity primarily comprised of $10.7 million favorable change in impairment and restructuring charges, $2.7 million favorable change in non-cash interest expense and the amortization of deferred financing fees and $1.8 million in other non-cash charges offset in part by $4.3 million in unfavorable changes in depreciation, depletion and amortization expense and $3.9 million in unfavorable changes in loss on disposal and sale of assets. The $6.7 million favorable change in working capital primarily comprised a $6.1 million favorable change in deferred revenue compounded by a $5.2 million favorable change in accounts payable and accrued expenses, a $4.9 million favorable change in inventory and a $3.8 million favorable change in other assets and accrued liabilities, offset in part by a $11.9 million change in net receivables and a $1.4 million in accrued interest expense.
Cash used in investing activities decreased $120.2 million to $14.7 million at December 31, 2016 from $134.9 million at December 31, 2015. The decrease of $120.2 million was primarily due to $115.0 million in cash from the contribution of Westmoreland Kemmerer LLC in 2015 compounded by $4.1 million favorable change in additions to property, plant, equipment and other, $3.3 million favorable change in advance royalties payments and $0.7 million favorable change in net proceeds from the sales of assets, offset in part by a $2.9 million unfavorable change in restricted investments and bond collateral.
Cash used in financing activities decreased $115.6 million to $15.0 million at December 31, 2016 from cash provided from financing activities of $100.6 million at December 31, 2015. The decrease of $115.6 million was primarily due to $120.9 million in proceeds from borrowing in 2015 primarily related to the Kemmerer Drop, compounded by $3.4 million unfavorable change in cash distributions to unitholders offset in part by $5.1 million favorable change in repayment of long-term debt and $3.6 million favorable change in debt issuance costs and other refinancing costs.
Year Ended December 31, 2015 (Successor) Compared to Period from January 1, 2014 through December 31, 2014 (Predecessor)
Net cash provided by operating activities increased $7.6 million due to a net loss for the year ended December 31, 2015 of $33.7 million, an increase of $9.5 million compared to a net loss for the predecessor period ended December 31, 2014 of $24.2 million. The increase in the net loss was attributable to lower coal sales volumes and cost incurred to execute the Kemmerer Drop. The $9.5 million increase in net loss combined with unfavorable changes in equity-based compensation of $4.1 million and an unfavorable change in working capital of $5.6 million was offset by favorable changes of $15.2 million in depreciation, depletion and amortization, $6.9 million of losses on disposals of assets and $2.7 million of accretion of asset retirement obligations.
Net cash used in investing activities increased $126.6 million which was largely attributable to $115.0 million cash used for the Kemmerer Drop combined with a decrease in cash provided from restricted investments and bond collateral of $4.7 million and an increase in capital expenditures of $115.0 million, offset in part by $2.8 million in proceeds from the sale of assets.
WESTMORELAND RESOURCE PARTNERS, LP AND SUBSIDIARIES
Net cash provided by financing activities increased $119.8 million due to net cash used in financing activities attributable to the $120.0 million in additional borrowing related to the Kemmerer Drop.
Period of December 31, 2014 (Successor)
Net cash used in operating activities was $1.8 million for the period of December 31, 2014 which comprised of net loss of $4.4 million that comprised of $2.8 million in restructuring charges and $1.6 million in loss on the extinguishment of debt offset in part by a $1.8 million change in working capital.
Net cash provided by financing activities of $7.7 million for the period of December 31, 2014 resulted from the refinancing of our pre-existing credit facility with a $175.0 million credit facility. Proceeds from the new credit facility were used to retire our then existing first and second lien credit facilities totaling $158.8 million and to pay $8.4 million in fees and expenses related to our new credit facility.
Contractual Obligations
1Represents payments due under the terms of the Services Agreement with our GP who provides services through its employees to us and is reimbursed for all related costs incurred on our behalf.
2In accordance with the contribution agreement related to the Kemmerer Drop, WCC shall, in compliance with the Services Agreement and the Partnership Agreement, allocate expenses incurred for post retirement pension, medical, and other benefit liabilities attributable to Transferred Employees on a cash basis through the period ending December 31, 2017. Thereafter, WCC shall allocate such expenses in its sole discretion, in compliance with the Services Agreement and the Partnership Agreement.
Critical Accounting Policies and Estimates
Use of Estimates
The preparation of financial statements in conformity with generally accepted accounting principles 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.
We have provided a summary of all significant accounting policies in Note 2. Summary Of Significant Accounting Policies to the consolidated financial statements. The most significant policies requiring the use of management estimates and assumptions relate to the collectability of accounts receivable, useful lives of fixed assets, valuation of coal reserves, reserve estimates of coal reserves, evaluations of asset impairment, recoverability of advanced royalties, useful lives of intangible assets, fair value of assets and liabilities under purchase accounting, and estimates of future asset retirement obligations. We believe that these significant policies involve a high degree of judgment and/or complexity.
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 coal processing plants in accordance with federal and state reclamation laws. Asset retirement obligations are based on projected pit configurations at the end of mining and are determined for each mine using estimates and
WESTMORELAND RESOURCE PARTNERS, LP AND SUBSIDIARIES
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. See Note 12. Asset Retirement Obligations to the consolidated financial statements for additional information.
Purchase and Pushdown Accounting
WCC's acquisition of our GP was accounted for using the acquisition method under ASC 805, Business Combinations. Under the acquisition method, the purchase price was allocated to the underlying tangible and intangible assets acquired and liabilities assumed based on their respective fair values. Per ASC 805-50-25-4 (effective November 18, 2014), we, as an acquiree of WCC through our GP, have the option to apply pushdown accounting in our consolidated financial statements when an acquirer (WCC) obtained control of us. We have chosen to adopt pushdown accounting and will reflect purchase accounting adjustments in our consolidated financial statement.
Recent Accounting Pronouncements
See Note 2. Summary Of Significant Accounting Policies to the consolidated financial statements 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 guarantees and financial instruments with off-balance sheet risk, such as letters of credit and surety, performance, and road bonds. No liabilities related to these arrangements are reflected in our consolidated balance sheet, and we do not expect any material adverse effects on our financial condition, results of operations or cash flows to result from these arrangements. Federal and state laws require us to secure certain long-term obligations, such as ARO, and contractual performance. Historically, we secured these obligations with surety bonds supported by letters of credit. See Note 21. Commitments And Contingencies to the consolidated financial statements for details on surety and performance bonds.
Item 7A.
Item 7A. Quantitative and Qualitative Disclosures About Market Risk
Market risk includes risks that arise from changes in interest rates, foreign currency exchange rates, commodity prices, equity prices and other market changes that affect market-sensitive instruments. We believe our principal market risks are commodity price risks and interest rate risks.
Commodity Price Risks
We manage our commodity price risks for coal sales through the use of supply contracts and the use of forward-purchase contracts. Some of the products used in our mining activities, such as diesel fuel, are subject to price volatility. Through our suppliers, we utilize forward-purchase contracts to manage the exposure related to this volatility. Additionally, our expected diesel fuel needs are protected, in varying amounts, by diesel fuel escalation provisions contained in coal supply contracts with some of our customers, allowing for changes in the price per coal ton sold when changes in diesel fuel pricing occur. Price changes typically lag the changes in diesel fuel costs by one quarter and are recorded in coal sales. Based on forecasted diesel fuel gallons to be used in 2017 and price protected diesel fuel gallons at December 31, 2016, a hypothetical increase of $0.30 per gallon for diesel fuel would decrease 2017 net income by $1.4 million.
For our contracts that are not cost protected in nature, we have exposure to inflation and price risk for supplies used in the normal course of production such as diesel fuel and explosives. In line with the worldwide mining industry, we have experienced increases from time-to-time in operating costs of mining equipment, diesel fuel and other supplies, such as tires. We manage these items through strategic sourcing contracts in normal quantities with our suppliers and may use derivatives. At December 31, 2016, we had fuel supply contracts outstanding with a minimum purchase requirement of 5.4 million gallons of diesel for 2017. These contracts qualify for the normal purchase normal sale exception under hedge accounting.
Interest Rate Risks
WESTMORELAND RESOURCE PARTNERS, LP AND SUBSIDIARIES
For the balance of our indebtedness that is not subject to the interest rate swap arrangements, we have exposure to changes in interest rates on our indebtedness associated with our 2014 Financing Agreement (Term Loan). At December 31, 2016, the weighted average cash interest rate on our debt under the 2014 Financing Agreement was 9.25%. Based on our borrowings at the end of 2016, a hypothetical 100 basis point increase in short-term interest rates would result, over the subsequent twelve-month period, in reduced net income of approximately $3.8 million.
Item 8.
Item 8. Financial Statements and Supplementary Data
The Report of Independent Registered Public Accounting Firm, Consolidated Financial Statements and supplementary financial data required for this Item are set forth on pages through of this Annual Report on Form 10-K and are incorporated herein by reference.
Item 9.
Item 9. Changes in and Disagreements With Accountants on Accounting and Financial Disclosure
None.
Item 9A.
Item 9A. Controls and Procedures
Conclusion Regarding the Effectiveness of Disclosure Controls and Procedures
As of December 31, 2016, management conducted an evaluation, under the supervision and with the participation of our Chief Executive Officer (“CEO”) and Interim Chief Financial Officer (“CFO”), of the effectiveness of the design and operation of our disclosure controls and procedures, as such term is defined in Rules 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 of December 31, 2016 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 to provide reasonable assurance 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.
Management’s Annual Report on Internal Control Over Financial Reporting
Management is responsible for establishing and maintaining adequate internal control over financial reporting, as such term is defined in Rules 13a-15(f) and 15d-15(f) under the Exchange Act. Internal control over financial reporting refers to a process designed by, or under the supervision of, our principal executive and principal financial officers or persons performing similar functions, and effected by the Board of Directors, management and other personnel, 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, and includes those policies and procedures that:
•
pertain to the maintenance of records that in reasonable detail accurately and fairly reflect the transactions and dispositions of our assets;
•
provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and that our receipts and expenditures are being made only in accordance with authorizations of our management and our directors; and
•
provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use, or disposition of our assets that could have a material effect on our financial statements.
Management evaluated the effectiveness of our internal control over financial reporting as of December 31, 2016, using the framework set forth by the Committee of Sponsoring Organizations of the Treadway Commission (COSO) in their 2013 Internal Control-Integrated Framework. Based upon management’s evaluation, our CEO and CFO concluded that our internal control over financial reporting was effective as of December 31, 2016.
Changes in Internal Control Over Financial Reporting
There have been no changes in our internal control over financial reporting (as defined in Rules 13a-15(f) and 15d-15(f) under the Exchange Act) during the year ended December 31, 2016 that have materially affected, or are reasonably likely to materially affect, our internal control over financial reporting.
WESTMORELAND RESOURCE PARTNERS, LP AND SUBSIDIARIES
Item 9B.
Item 9B. Other Information
None.
WESTMORELAND RESOURCE PARTNERS, LP AND SUBSIDIARIES
PART III
Item 10.
Item 10. Directors, Executive Officers and Corporate Governance
Partnership Management
We are managed and operated by the directors and executive officers of our general partner, Westmoreland Resources GP, LLC. As of December 31, 2016, WCC owned 93.91% of our limited partner interests on a fully diluted basis, 100% of the membership interests in our general partner and our incentive distribution rights. Our general partner was not elected and is not subject to election in the future by our unitholders. Our general partner has a Board of Directors (the "Board"), and our unitholders are not entitled to elect the directors or participate in our management or operations. Our general partner owes certain fiduciary duties to our unitholders as well as a fiduciary duty to its owners. Our general partner is liable, as general partner, for all of our debts (to the extent not paid from our assets), except for indebtedness or other obligations that are made specifically nonrecourse to it. Whenever possible, we intend to incur indebtedness that is nonrecourse to our general partner.
For the majority of 2016, our general partner’s Board of Directors had eight directors, four of whom are "independent" as defined under the independence standards established by the NYSE and the Exchange Act. The NYSE does not require a listed publicly traded partnership, such as ours, to have a majority of independent directors on the Board of Directors of its general partner or to establish a compensation or nominating committee. However, our general partner is required to have an audit committee of at least three members, and all of its members are required to meet the independence and experience standards established by the NYSE and the Exchange Act. Our general partner’s Board of Directors has affirmatively determined that Robert T. Clutterbuck, Keith D. Horton, Kurt D. Kost and Gerald A. Tywoniuk are independent as described in the rules of the NYSE and the Exchange Act. Effective December 15, 2016, Jason W. Veenstra resigned from the Board and he was not replaced. Mr. Veenstra was an employee director that was not paid for his service on the Board.
In this report, we provide executive compensation information on our general partner’s principal executive officer, current and former principal financial officer, and our next three most highly paid executive officers, for the fiscal year 2016, based on total compensation determined under Item 402 of Regulation S-K. We refer to these officers in this report as our “named executive officers.” All of our general partner’s named executive officers are employed by WCC. Our general partner’s executive officers allocate their time between managing our business and affairs and those of WCC. Such executive officers devote as much time to the management of our business and affairs as is necessary for the proper conduct of our business. However, certain of these executive officers devoted a majority of their professional time to WCC during 2016. Our named executive officers participate in the employee benefit plans and compensation arrangements of WCC, and the compensation committee of WCC’s Board of Directors sets the components of their compensation, including salary, annual incentive and long-term incentive plans. We have no control over this compensation determination process. Please refer to WCC’s Proxy Statement for its 2017 Annual Meeting of Shareholders (the "WCC Proxy Statement") for further information on the compensation of certain of our named executive officers during 2016.
Under the terms of our Services Agreement with WCC, we pay a fixed management fee in connection with our general partner’s management of our business. We also reimburse our general partner and its affiliates (including WCC) for direct costs and expenses they incur and payments they make in providing general and administrative services for our benefit. Corporate and other costs and expenses incurred by WCC and its affiliates that are directly attributable to Partnership entities will be allocated to us. WCC allocates these corporate and other costs on the basis of the costs and the level of support attributable to the applicable operating facilities for each function performed by the WCC (e.g., legal, accounting, treasury, insurance administration and claims processing, risk management, health, safety and environmental, information technology, human resources, credit, payroll, internal audit, taxes and engineering), rather than on the basis of time spent by individual officers acting within a function. The estimated cost and level of support for each of our operating facilities is based on a weighted average of certain factors determined by management of WCC, including the type of operations and headcount at the facilities supported. Our Partnership Agreement does not set a limit on the amount of expenses for which our general partner and its affiliates may be reimbursed.
Where costs are specifically incurred on behalf of one of our affiliates, the costs are billed directly to us by WCC under the Services Agreement. Costs may also be allocated to us in a variety of methods when a cost or service applies equally to all employees. Additionally, the Services Agreement provides for an annual fixed fee to reimburse our general partner for executive officers and other employees who devote less than a majority of their time to us. Each year, our general partner determines the aggregate amount, including the annual fixed fee, to be reimbursed to WCC, by us, taking into account the totality of services performed for our benefit by the executive officers during the calendar year. The amounts reimbursed to WCC are not calculated with regard to an executive officer's time spent on our business matters versus those of WCC. There is no specific allocation of a portion of a shared officer's compensation in connection with services rendered on our behalf. During 2016, WCC allocated $71.2
WESTMORELAND RESOURCE PARTNERS, LP AND SUBSIDIARIES
million of expenses in the aggregate for the services they provided to us, of which $2.2 million is attributable to the annual fixed fee consisting of $0.8 million for executive services and $1.4 million for corporate and other costs described above. See Item 13 - Certain Relationships and Related Transactions, and Director Independence for further discussion of our relationships and transactions with WCC and its affiliates.
Directors and Executive Officers
Directors of our general partner, which we refer to as our Board, are appointed for a term of one year and hold office until their successors have been elected or qualified or until the earlier of their death, resignation, removal or disqualification. All of the directors of our general partner were appointed to the Board on January 6, 2015. The executive officers of our general partner serve at the discretion of the Board. The following table shows certain information for the directors and executive officers of our general partner from January 1, 2016 to December 31, 2016.
1 Mr. Troup was appointed Interim Chief Financial Officer on November 15, 2016.
2 Mr. Veenstra resigned from his positions effective December 15, 2016.
Kevin A. Paprzycki, was elected and has served as a member of our Board since January 6, 2015, and he has served as Chief Executive Officer and President of our general partner since December 1, 2015. He was previously appointed Chief Financial Officer and Treasurer of our general partner in December 2014, and held the Treasurer title until July 2015. Mr. Paprzycki joined WCC as Controller and Principal Accounting Officer in June 2006 and was named Chief Financial Officer in April 2008, and then Treasurer in June 2010. Prior to WCC, Mr. Paprzycki was Corporate Controller at Applied Films Corporation from 2005 to 2006. Mr. Paprzycki became a certified public accountant in 1994 and a certified financial manager and certified management accountant in 2004. His experience at WCC with the coal industry and as Chief Financial Officer provide him with the necessary skills to be a member of the Board. Mr. Paprzycki earned his B.S. in Accountancy from Case Western Reserve University and his M.B.A. from the University of Utah.
Nathan M. Troup, was appointed Interim Chief Financial officer of our general parter on November 15, 2016. Mr. Troup has been the Chief Accounting Officer and Corporate Controller at WCC since June 9, 2015. Mr. Troup has 16 years of experience in public company accounting and auditing. From July 2011 to June 2015, Mr. Troup served as the Chief Accounting Officer and Controller, as well as various other positions, with DigitalGlobe, Inc., a leading provider of geospatial information products and services sourced from its own advanced satellite constellation. From August 2010 to June 2011, Mr. Troup was a Senior Manager with The Siegfried Group, LLP, which is a professional services firm that provides outsourced accounting and finance support to Fortune 1000 clients. From 2001 to July 2010, Mr. Troup worked as an auditor for Ernst and Young, LLP. Mr. Troup is a Certified Public Accountant and holds a Master of Accounting and a Bachelor of Science in Accountancy from the University of Missouri, Columbia.
Jennifer S. Grafton has served as Chief Legal Officer of our general partner since January 1, 2015, and Secretary from January 1 until February 18, 2015. She was elected and has served as a member of the Board since January 6, 2015. Ms. Grafton joined WCC as Associate General Counsel in December 2008. She was named General Counsel and Secretary in February 2011 and was promoted to Senior Vice President, Chief Administrative Officer and Secretary in November 2014. Prior to WCC, Ms. Grafton worked in the corporate group of various Denver-based and national law firms focusing her practice on securities and corporate governance. She is a member of the Colorado bar. Ms. Grafton’s experience at WCC with the coal industry as Associate General Counsel, General Counsel and then Senior Vice President and Chief Administrative Officer provide her with the necessary skills to be a member of the Board. Ms. Grafton graduated from the University of Michigan Ross School of
WESTMORELAND RESOURCE PARTNERS, LP AND SUBSIDIARIES
Business with her M.B.A. with High Distinction, graduated from the University of Denver Sturm College of Law with her J.D., Order of St. Ives, and received her B.S. from the University of Puget Sound.
Charles C. Ungurean served as President and Chief Executive Officer of our general partner from its formation in 2007 through December 31, 2014, and has served as a member of the Board since its formation in 2007. In 1985, he co-founded our predecessor and wholly owned subsidiary, Oxford Mining Company. Mr. Ungurean served as President and Treasurer of our predecessor from 1985 to August 2007. He currently serves on the Board of Directors of the National Mining Association. In addition, Mr. Ungurean served as Chairman of the Ohio Coal Association from July 2002 to July 2004. His more than 40 years of experience in the coal industry, over 25 of which have been spent running our operations or the operations of our predecessor and wholly owned subsidiary, Oxford Mining Company, provide him with the necessary skills to be a member of the Board and a member of the executive committee of our general partner. Mr. Ungurean received a B.A. in General Studies from Ohio University and is a certified surface mine foreman in Ohio.
Robert T. Clutterbuck was elected and has served as a member of the Board since January 6, 2015. He has been the managing partner and portfolio manager at Clutterbuck Capital Management LLC for the past nine years. Prior thereto, Mr. Clutterbuck was Chairman of Key Capital Partners, which provided brokerage, capital markets, insurance, investment banking and asset management expertise to business and private clients nationwide. He was also Chief Executive Officer of McDonald Investments Inc. and was a Senior Executive Vice President of KeyCorp. In addition to serving on the McDonald Investments Board, Mr. Clutterbuck has served on numerous philanthropic boards as well as several advisory boards of financial institutions. His extensive financial experience provide him with the necessary skills to be a member of the Board and a member of the audit committee of our general partner. With respect to the audit committee, Mr. Clutterbuck was designated as financially literate in accordance with NYSE listing standards based on his education and experience. He earned a bachelor’s degree from Ohio Wesleyan University and a M.B.A. from the University of Pennsylvania Wharton School of Business.
Keith D. Horton was elected and has served as a member of the Board since January 6, 2015. On January 1, 2015, he retired from his position as President of PVR Coal, a subsidiary of Regency Gas Partners. From March 2010 until March 2014, Mr. Horton was Executive Vice President and Chief Operating Officer - Coal at PVR Partners, a publicly traded master limited partnership. He has an extensive background in coal operations and management, including a mine engineer position with WCC that was his first position out of college. Mr. Horton’s extensive experience in the coal industry provide him with the necessary skills to be a member of the Board, a member of the executive and audit committees of our general partner. With respect to the audit committee, Mr. Horton was designated as financially literate in accordance with NYSE listing standards based on his education and experience. He earned a bachelor’s degree in Engineering of Mines from West Virginia University and completed the University of Virginia Darden School of Business’ Executive Management Program.
Kurt D. Kost was elected and has served as a member of the Board since January 6, 2015. He has over 35 years experience in the mining industry. Mr. Kost’s expertise includes coal operations and engineering; safety and process management related to operational and maintenance improvements; deploying technology in practical field applications; post-merger organization design and implementation; and executive management and leadership. From September of 2013 until May of 2014 he was a Senior Vice President with Norwest Corporation and from 2009 until 2012 was President of Alpha Natural Resources. Mr. Kost’s extensive experience in the coal industry provide him with the necessary skills to be a member of the Board and a member of the audit committee of our general partner. With respect to the audit committee, Mr. Kost was designated as financially literate in accordance with NYSE listing standards based on his education and experience. Mr. Kost earned a bachelor’s degree in Mining Engineering from South Dakota School of Mines and Technology and in 2004 completed Harvard Business School’s Advanced Management Program.
Gerald A. Tywoniuk has served as a member of the Board since January 2009. He also serves as a director and audit committee chairperson of the general partner of American Midstream Partners, LP, as well as a director and audit committee member of the general partner of Landmark Infrastructure Partners LP. In addition to his board of director roles, Mr. Tywoniuk has provided various interim and project Chief Financial Officer services since May 2010. From June 2008 until August 2013, he held various management and finance roles, including Plan Representative, acting Chief Executive Officer, and Chief Financial Officer of Pacific Energy Resources Ltd., an oil production company. Mr. Tywoniuk joined that company in June 2008 to help the management team work through the company’s financially distressed situation. The board of the company elected to file for Chapter 11 protection in March 2009. In December 2009, the company completed the sale of its assets, and by August 2013 the company completed its liquidation. Mr. Tywoniuk previously served as Chief Financial Officer of Pacific Energy Partners, LP, an oil and refined products pipeline and storage partnership from 2002 to 2006, and MarkWest Energy Partners, L.P. and its predecessor, principally a natural gas and liquids midstream services partnership, from 1997 to 2002. He has over 34 years of experience in accounting and finance, including 12 years as the Chief Financial Officer of three public companies and 4 years as Vice President/Controller of a fourth public company. Mr. Tywoniuk’s extensive accounting, financial and executive management
WESTMORELAND RESOURCE PARTNERS, LP AND SUBSIDIARIES
experience, as well as his in-depth knowledge of the mining industry generally and our partnership in particular, and his prior experience with publicly traded partnerships, provide him with the necessary skills to be a member of the Board of Directors and a member and chairman of the audit committee of our general partner. With respect to the audit committee, Mr. Tywoniuk was designated as an audit committee financial expert and financially literate in accordance with NYSE listing standards based on his education and experience. He earned a Bachelor of Commerce degree from The University of Alberta, Canada, and is a Canadian chartered accountant.
Gregory J. Honish has served as Senior Vice President, Operations of our general partner since March 2009. Mr. Honish has served in other capacities with us and our predecessor since January 1999, including Vice President, Mining and Business Development from September 2007 to March 2009 and Senior Mining Engineer from January 1999 to September 2007. Mr. Honish has held various positions in engineering, operations and management in the coal industry during his more than thirty-year professional career at mines in Northern Appalachia, Central Appalachia, the Illinois Basin and the Powder River Basin. He is a licensed professional engineer in Ohio and West Virginia and a certified surface mine foreman in Ohio and Wyoming. Mr. Honish received a B.S. in Mining Engineering from the University of Wisconsin.
Michael J. Meyer was appointed Chief Accounting Officer in February of 2015 and has served as Controller of our general partner since October 2012. Prior to joining Westmoreland GP, he was an Internal Audit Manager with L Brand, a specialty retailer, from May 2010 through October 2012. Mr. Meyer has over 11-years of public accounting experience and has focused on global consumer industrial clients. Prior to May 2010, Mr. Meyer was an Audit Senior Manager with KPMG LLP. He earned a B.B.A. with a double major in accounting and finance from the Carl H. Lindner College of Business at the University of Cincinnati in June of 1999 and became a certified public accountant in March 2002.
Jason W. Veenstra resigned from the Board and his positions as Chief Financial Officer and Treasurer effective December 15, 2016. He was Treasurer of our general partner from July 27, 2015, until he was appointed Chief Financial Officer, Treasurer and Director of our general partner on December 1, 2015. Mr. Veenstra was also appointed Chief Financial Officer at WCC on December 1, 2015, where he had previously held the role of CFO - Canada from April 2014. Previously Mr. Veenstra had held various roles at Sherritt International from 2006 until 2014, including serving as director of business development and Chief Financial Officer for the coal division. Mr. Veenstra received a bachelor of Commerce degree in Accounting from the University of Alberta and articled at Ernst & Young LLP to complete his Chartered Accountant designation.
Corporate Governance
The Board has adopted corporate governance guidelines to assist it in the exercise of its responsibilities to provide effective governance over our affairs for the benefit of our unitholders. In addition, we have adopted a code of business conduct and ethics, which sets forth legal and ethical standards of conduct for all our officers, directors and employees, as applicable. The corporate governance guidelines, the code of business conduct and ethics, the charters of our audit and executive committees and our lead independent director charter are available on our website at www.westmorelandMLP.com and in print without charge to any unitholder who requests any of them. A unitholder may make such a request in writing by mailing such request to Investor Relations, Westmoreland Resource Partners, LP, 9540 South Maroon Circle, Suite 300, Englewood, Colorado 80112, or by emailing such request to Investor Relations at ir@westmoreland.com. Amendments to, or waivers from, the code of business conduct and ethics will also be available on our website and reported as may be required under SEC rules; however, any technical, administrative or other non-substantive amendments to the code of business conduct and ethics may not be posted. Please note that the preceding Internet address is for information purposes only and is not intended to be a hyperlink. Accordingly, no information found or provided at that Internet address or at our website in general is intended or deemed to be incorporated by reference herein.
Board Meetings; Committees of the Board of Directors
Our Board has audit, executive and conflicts committees. Our Board dissolved our compensation committee as of February 24, 2016. However, the full Board approves equity grants when necessary. No grants of Partnership equity were awarded to executive officers during 2016. The Board held ten meetings in fiscal year 2016. Each director who served during fiscal year 2016 attended at least 90 percent of the meetings of the Board and 90 percent of the meetings of the committees on which he or she served during the periods that he or she served.
Audit Committee Report and Independence
The Board has established an audit committee (the “Audit Committee”) that complies with NYSE requirements and Section 3(a)(58)(A) of the Exchange Act. Our general partner is required to have at least three independent directors serving on
WESTMORELAND RESOURCE PARTNERS, LP AND SUBSIDIARIES
its board at all times. Gerald A. Tywoniuk, Robert T. Clutterbuck, Keith D. Horton and Kurt D. Kost are our independent directors and serve as the members of the Audit Committee, and all have the requisite education and experience sufficient to be designated as financially literate under NYSE listing standards. The Board has determined that Mr. Tywoniuk, who serves as the chairman of the Audit Committee, has the accounting or related financial management expertise sufficient to qualify as the Audit Committee financial expert in accordance with Item 401 of Regulation S-K.
The Audit Committee meets on a regularly-scheduled basis and with our independent accountants at least four times each year. The Audit Committee has the authority and responsibility to review our external financial reporting, to review our procedures for internal auditing, to review the adequacy of our internal accounting controls, to consider the qualifications and independence of our independent accountants, to engage and resolve disputes with our independent accountants, including the letter of engagement and statement of fees relating to the scope of the annual audit work and any special audit work that may be recommended or required by the independent accountants, and to engage the services of any other advisors and accountants as the Audit Committee deems advisable. The Audit Committee reviews and discusses the audited financial statements with management, discusses with our independent auditors matters required to be discussed by statement on auditing standards No. 16 (PCAOB Auditing Standard No. 16, Communications With Audit Committees, Related Amendments to PCAOB Standards and Transitional Amendments to AU Section 380), and makes recommendations to the Board regarding the inclusion of our audited financial statements in this Annual Report on Form 10-K.
Conflicts Committee
Our partnership agreement provides for the conflicts committee (the “Conflicts Committee”), as circumstances warrant, to review conflicts of interest between us and our general partner or between us and affiliates of our general partner. The Conflicts Committee, consisting solely of independent directors, determines if the resolution of a conflict of interest that has been presented is fair and reasonable to us. The members of the Conflicts Committee may not be executive officers or employees of our general partner or directors, executive officers or employees of its affiliates. In addition, the members of the Conflicts Committee must meet the independence and experience standards established by the NYSE and the Exchange Act. The composition of our Audit Committee qualifies it to be, and our Audit Committee presently serves as, our Conflicts Committee.
Executive Committee
The Board of Directors of our general partner has established an executive committee (the “Executive Committee”). The Executive Committee handles matters that arise during the intervals between meetings of the Board of Directors and that, in the opinion of the chairman of the Executive Committee, do not warrant convening a special meeting of the Board of Directors but should not be postponed until the next scheduled meeting. Kevin A. Paprzycki, Keith D. Horton and Charles C. Ungurean serve as the members of the Executive Committee. Mr. Paprzycki serves as the chairman of the Executive Committee.
Meeting of Non-Management Directors and Communications with Directors
At least quarterly, all of the independent directors of our general partner meet in an executive session without management participation or participation by non-independent directors. Mr. Gerald A. Tywoniuk, as chairman of the Audit Committee, presides over these executive sessions.
The Board of Directors of our general partner welcomes questions or comments about us and our operations. Unitholders or interested parties may contact the Board of Directors, including any individual director, by contacting the Secretary of our general partner at www.westmorelandMLP.com/investors/investor-relations-contact-form/ or at the following address: Name of the Director(s), c/o Secretary, Westmoreland Resource Partners, LP, 9540 South Maroon Circle, Suite 300, Englewood, Colorado 80112. Please note that the preceding Internet address is for information purposes only and is not intended to be a hyperlink. Accordingly, no information found or provided at that Internet address or at our website in general is intended or deemed to be incorporated by reference herein.
Section 16(a) Beneficial Ownership Reporting Compliance
Section 16(a) of the Exchange Act requires the Board and executive officers of our general partner, and persons who own more than 10 percent of a registered class of our equity securities, to file with the SEC and any exchange or other system on which such securities are traded or quoted initial reports of ownership and reports of changes in ownership of our common units and other equity securities. Officers, directors and greater than 10 percent unitholders are required by the SEC’s regulations to furnish to us and any exchange or other system on which such securities are traded or quoted with copies of all Section 16(a) forms they filed with the SEC. To our knowledge, based solely on a review of the copies of such reports furnished to us and
WESTMORELAND RESOURCE PARTNERS, LP AND SUBSIDIARIES
written representations that no other reports were required, we believe that all reporting obligations of the officers, directors and greater than 10 percent unitholders of our general partner under Section 16(a) were satisfied during the year ended December 31, 2016, other than a late Form 4 filing by WCC filed on December 8, 2016.
Item 11.
Item 11. Executive Compensation
On December 31, 2014, our general partner was acquired by WCC. All of our named executive officers are employed by WCC. Accordingly, required compensation disclosures for those of our named executive officers who are executive officers of WCC will be contained in the WCC Proxy Statement. These include, but are not limited to, disclosure regarding: Grants of Plan Based Awards, Outstanding Equity Awards at Fiscal Year End, Option Exercises and Stock Vested for those named executive officers. Mr. Honish is the only named executive officer that was compensated for services to the Partnership as a named executive officer prior to our general partner's acquisition by WCC. As such, there are no compensation disclosures in the Summary Compensation Table below with respect to our named executive officers, other than Mr. Honish, for periods prior to fiscal year 2015.
Compensation Discussion and Analysis
We are managed by the executive officers of our general partner who are employed by WCC and participate in the employee benefit plans and compensation arrangements of WCC. Four of our named executive officers, Messrs. Paprzycki, Troup and Veenstra, and Ms. Grafton, were also executive officers of WCC for all or some of 2016. The board of directors does not have a compensation committee. For fiscal year 2016, all of our named executive officers were compensated directly by WCC pursuant to the Services Agreement. All decisions as to the compensation of our named executive officers are made by the compensation committee of WCC. Therefore, we do not have any policies or programs relating to compensation of the executive officers of our general partner, we make no decisions relating to such compensation and we have no control over determining such compensation. Other than any awards that may be granted in the future under our Original LTIP or New LTIP, the compensation of our general partner’s executive officers currently is, and in the future will be, set by WCC. The executive officers of our general partner will continue to participate in WCC’s employee benefit plans and arrangements, including any WCC plans that may be established in the future.
Pursuant to the terms of our Services Agreement, we reimburse WCC for a portion of WCC's compensation expense related to our general partner’s executive officers (which expenses include the share of the compensation paid to the executive officers of our general partner attributable to the time they spend managing our business). See “Item 13, Certain Relationships and Related Transactions, and Director Independence - Services Agreement” for information regarding the Services Agreement and allocation of expenses between the entities that share the services of these executives. Currently, none of the executive officers of our general partner has an employment agreement with us or is otherwise specifically or directly compensated by us for his service as an executive officer of our general partner.
A full discussion of the policies and programs of the Compensation Committee of WCC will be set forth in the WCC Proxy Statement which will be available upon its filing on the SEC’s website at www.sec.gov and on WCC’s website at www.westmoreland.com at the “Investors - SEC Filings” tab. The WCC Proxy Statement also will be available upon request, free of charge, from the Corporate Secretary of our general partner.
WESTMORELAND RESOURCE PARTNERS, LP AND SUBSIDIARIES
Summary Compensation Table
The following table sets forth certain information with respect to WCC's compensation of our named executive officers, consisting of our principal executive officer, our interim chief financial officer who currently serves as our principal financial officer, our former principal financial officer who served during a portion of fiscal year 2016, and our three other most highly compensated executive officers. The table summarizes the compensation attributable to services performed by our named executive officers who are not also named executive officers of WCC during fiscal year 2016, all of which compensation was determined and paid by WCC. Information for 2014 has been included for Mr. Honish due to his status as a named executive officer of our predecessor, Oxford Resource Partners, LP, in 2014, during which time his compensation was determined by our compensation committee. Mr. Honish’s 2015 compensation was determined pursuant to an employment agreement that expired on December 31, 2015. Further information regarding the compensation of Messrs. Paprzycki, Troup and Veenstra, and Ms. Grafton, the named executive officers who were also named executive officers of WCC for all or a portion of 2016, will be set out in the WCC Proxy Statement. Compensation amounts set forth in the WCC Proxy Statement will include all compensation paid by WCC, including the amounts shown in the table below, which are attributable to services performed for us.
1 Messrs. Paprzycki, Veenstra and Troup, and Ms. Grafton, split their professional time in 2016 between WCC and us, and all compensation paid to them is determined by WCC. In accordance with SEC rules, a portion of the total compensation paid by WCC to these named executive officers is allocated to the services performed for us, based on an estimate of the portion of each named executive officer's compensation which was reimbursed by us to WCC pursuant to the terms of the Services Agreement. During fiscal year 2016, the applicable allocation for Mr. Paprzycki was 40%, Ms. Grafton was 30% and Mr. Veenstra was 30%. Mr. Veenstra resigned from his position as our General Partner’s Chief Financial Officer on December 15, 2016, and was replaced on an interim basis by Mr. Troup. As such, on December 15, 2016, Mr. Veenstra's allocation ceased and Mr. Troup's allocation became 30%. The total compensation paid by WCC to Messrs. Paprzycki, Troup and Veenstra, and Ms. Grafton, in 2016, as well as a discussion of how their compensation was determined, is disclosed in the WCC Proxy Statement. Messrs. Meyer and Honish were also employees of WCC and their compensation was determined by WCC. However, under the Services Agreement, since Messrs. Meyer and Honish each devoted substantially all of his professional time in 2016 providing services to the Partnership, the costs of their employment have been passed on to us. Mr. Honish’s 2015 compensation was determined pursuant to an employment agreement that expired on December 31, 2015. For the fiscal year 2014, prior to the acquisition of the general partner by WCC, Mr. Honish's compensation was wholly determined and calculated by the compensation committee of our predecessor at that time.
2 In 2014, Mr. Honish received a $140,000 retention bonus paid during 2014 prior to the acquisition of our general partner by WCC. Mr. Honish's employment agreement for 2015 included a cash bonus of 100% of salary, which was awarded to him for his performance in 2015. For 2016, Messrs. Honish and Meyer were part of WCC's annual incentive plan for non-equity incentive compensation ("AIP"), which was determined solely by WCC, and is more thoroughly described in the WCC Proxy Statement. Mr. Honish was awarded an AIP bonus of $50,451 and Mr. Meyer was awarded an AIP bonus of $34,733. Mr. Honish's AIP bonus paid out at 84% of target based on achieving 78% of financial performance for Partnership mines in Ohio, 76% safety performance for Partnership mines in Ohio, and an individual performance of 100%. Mr. Meyer's AIP bonus paid out at 107% of target based on achieving 135% of financial performance on a Westmoreland global consolidated financial basis, 100% safety performance on a Westmoreland global consolidated safety basis, and an individual performance of 100%.
WESTMORELAND RESOURCE PARTNERS, LP AND SUBSIDIARIES
3 No Partnership equity was awarded to the named executive officers for 2016. Messrs. Honish and Meyer's 2016 stock grant was determined solely by WCC and granted solely in WCC equity. Mr. Meyer's grants consisted of 900 time-based restricted stock units ("RSU") representing common stock vesting annually in thirds and 1,500 performance-based RSUs that vest in their entirety after three years upon attainment of previously determined performance goals. Mr. Honish's grants consisted of 2,250 time-based RSU representing common stock vesting annually in thirds and 3,750 performance-based RSUs that vest in their entirety after three years upon attainment of previously determined performance goals. The amounts shown represent the grant date fair value of the awards computed in accordance with FASB ASC Topic 718. Please refer to the "Grants of Plan-Based Awards" and "Outstanding Equity Awards at Fiscal Year-End" tables in the WCC Proxy Statement for further details regarding equity held by Messrs. Paprzycki, Troup and Veenstra, and Ms. Grafton. The following tables describe Messrs. Honish and Meyer's long-term incentive awards wholly determined by WCC and granted in WCC RSUs during 2015 and 2016.
4 No Partnership stock options were awarded during 2016 and each of Messrs. Meyer and Honish have no outstanding options in Partnership or WCC equity. For Messrs. Paprzycki, Troup and Veenstra, and Ms. Grafton, the number and value of outstanding WCC equity awards (including unexercised stock options) at year-end is reported in the WCC Proxy Statement.
5 Neither the Partnership nor WCC actively maintains a pension plan, nor a non-qualified deferred compensation plan, for executives. Effective July 1, 2009, WCC froze its pension plan for non-union employees, including named executive officers, resulting in no future benefits accruing under these plans. Please refer to the "Pension Benefits Upon Retirement, Termination, Disability or Death" table in the WCC Proxy Statement for further details on current pension balances for Messrs. Paprzycki and Ms. Grafton.
6 For named executive officers, the 2016 amounts shown include a matching contribution by WCC under its 401(k) plan, which matched 6% of the executives salary in cash contributions, until September 30, 2016, when WCC began matching contributions at a 4% rate, up to the maximum amount allowed under the Internal Revenue Code of 1986, as amended (the "Code"), and is more thoroughly described in the WCC Proxy Statement.
Outstanding Equity Awards
The following tables describe Messrs. Honish and Meyer's long-term incentive awards wholly determined by WCC and granted in WCC equity during 2015 and 2016. Please refer to the "Grants of Plan-Based Awards" and "Outstanding Equity Awards at Fiscal Year-End" tables in the WCC Proxy Statement for further details regarding equity held by Messrs. Paprzycki, Troup and Veenstra, and Ms. Grafton. None of the named executive officers of our general partner participate in any non-qualified deferred compensation plans.
2016 Grants of Plan-Based Awards
1 The awards granted in WCC common equity to the WMLP named executive officers on May 18, 2016, consisted of time-based restricted stock units with a three-year vesting period, performance-based restricted stock units with a three-year cliff vest and time-based cash units with a three year vesting period. Amounts in this column represent the aggregate grant date fair value of the equity awarded calculated in accordance with Financial Accounting Standards Board Accounting Standards Codification Topic 718 - Share-Based Payment. Participants in the WCC long term incentive program also received new time-based Cash Unit Award grants, in lieu of an equal amount of time-based equity grants thereby reducing the amount of time-based restricted stock units received by participants, which are paid out in cash but linked to WCC's stock price on the vesting date.
WESTMORELAND RESOURCE PARTNERS, LP AND SUBSIDIARIES
2016 Outstanding Equity Awards at Fiscal Year-End
1 Awards in this column consist of WCC equity time-based restricted stock units with a grant dates of April 1, 2015 and May 18, 2016. Awards of the time-based restricted stock units vest in thirds over a three-year period, each time on April 1st. To the extent vested in the last year, these shares are reflected in the “Options Exercised and Stock Vested in 2016” table below.
2 The market value of the awards of the WCC equity restricted stock units that have not yet vested was determined by multiplying the closing price of a share of WCC common stock on December 31, 2016 ($17.67) by the number of shares.
3 Awards in this column consist of performance-based restricted stock units with a grant date of April 1, 2015 and May 18, 2016. These awards pay out at threshold, target and maximum performance goals, wholly determined by the compensation and benefits committee of WCC, depending on the achievement of a multi-indexed total stockholder return metric in 2015; and a combination multi-indexed total stockholder return metric and free cash flow metric in 2016. Contingent on achievement of the performance goal during the three year performance period, these awards will cliff vest on April 1, 2018, and April 1, 2019. If threshold performance is not achieved, all awards will forfeit. In 2016, previous performance-based awards paid out at the maximum so the number of shares shown in this column also shows payout at maximum levels.
Options Exercised and Stock Vested in 20162
1 The market value of the WCC common stock awards was determined by multiplying the actual vesting date market value at close on April 6, 2016, which was $7.13.
2 No WMLP named executive officers exercised any Partnership or WCC equity options during fiscal year 2016.
Long-Term Incentive Plan
In October 2016, by consent of our majority unitholder, we adopted the Westmoreland Resources, LP, Long Term Incentive Plan (the "New LTIP"). The New LTIP allows for grants of (1) restricted units, (2) unit appreciation rights, referred to as UARs, (3) unit options, referred to as Options, (4) phantom units, (5) unit awards, (6) substitute awards, (7) other Unit-based awards, (8) cash awards, (9) performance awards and (10) distribution equivalent rights, referred to as DERs ((1)-(9) collectively, "New LTIP Awards"). Our previous long term incentive plan was originally adopted in 2007 in connection with our formation and subsequently amended and restated in July 2010 in connection with our initial public offering (the "Original LTIP" or, collectively with the New LTIP, the "LTI Plans"). The Original LTIP allows for grants of (1) restricted units, (2) unit appreciation rights, referred to as UARs, (3) unit options, referred to as Options, (4) phantom units, (5) unit awards, (6) substitute awards, (7) other Unit-based awards, (8) cash awards, (9) performance awards and (10) distribution equivalent rights, referred to as DERs ((1)-(9) collectively with the New LTIP Awards, "Awards"). The LTI Plans provide for flexibility in determining the compensatory arrangements for employees, officers, consultants, and directors of our general partner and any of its affiliates providing services to us. However, the only equity issued under the Original LTIP as of December 31, 2016 were annual grants of phantom units to our non-employee directors of our general partner, no equity has been issued under the New LTIP. Please see the section entitled “Director Compensation” for additional information regarding the compensation program for the non-employee directors of our general partner.
WESTMORELAND RESOURCE PARTNERS, LP AND SUBSIDIARIES
The LTI Plans are administered by the Board, or an alternative committee appointed by the Board, which we refer to together as the “committee” for purposes of this summary. The committee has the power to determine to whom and when awards will be granted, determine the amount of Awards (measured in cash or in shares of our common units), proscribe and interpret the terms and provisions of each Award agreement (the terms of which may vary), accelerate the vesting provisions associated with an Award, delegate duties under the LTI Plans and execute all other responsibilities permitted or required under the LTI Plans. The maximum aggregate number of common units that may be issued pursuant to the Original LTIP is 233,840 common units and pursuant to the New LTIP is 500,000, in each case subject to adjustment due to recapitalization or reorganization, or related to forfeitures or the expiration of Awards, in each case as provided under the LTI Plans.
If a common unit subject to any Award is not issued or transferred, or ceases to be issuable or transferable for any reason, including (but not exclusively) because units are withheld or surrendered in payment of taxes or any exercise or purchase price relating to an Award or because an Award is forfeited, terminated, expires unexercised, is settled in cash in lieu of common units, or is otherwise terminated without a delivery of units, those common units will again be available for issue, transfer, or exercise pursuant to Awards under the LTI Plans, to the extent allowable by law. Common units to be delivered pursuant to awards under our LTI Plans may be common units acquired by our general partner in the open market, from any other person, directly from us, or any combination of the foregoing.
WCC Compensatory Plans, Agreements, and Programs
Retirement Benefits
WCC does not maintain any tax-qualified defined benefit pension plan for executives or supplemental executive retirement plan. However, our named executive officers have the opportunity to participate in the WCC and Subsidiaries Employees’ Savings Plan (the “WCC 401(k) Plan”), a tax qualified defined contribution plan designed primarily to help participating employees accumulate funds for retirement. Our named executive officers may make elective contributions, and WCC made matching contributions equal to 100 percent of employee contributions up to 6 percent of eligible compensation through September 30, 2016, and up to 4 percent of eligible compensation thereafter. All named executive officers are eligible to receive these contributions.
Severance and Change in Control Benefits
WCC eliminated its formal severance policy in December 2016 and, as such, our named executive officers are not automatically eligible for severance benefits upon discontinued employment. We have no executives working under employment contracts. WCC's AIP provides that program participants are only entitled to payment of incentive payouts if they are employed on the date of payment, which typically occurs in April of the following year, although this requirement is deemed fulfilled upon death or disability. All incentive payouts are forfeited in the event a named executive officer leaves employment for any reason, unless expressly agreed to by WCC's compensation and benefits committee. Upon death or disability, the performance-based restricted stock units are earned on a pro-rata basis based on the date of death or disability. The recipient's earned pro-rata share will not vest until the normal vesting date for the award, occurring on April 1st of the third anniversary of the grant date, and the final determination of the amount of the award contingent on the final performance determination of the performance metric. WMLP named executive officers do not receive additional benefits in the event of a retirement.
For further discussion on potential payments owed to Messrs. Paprzycki and Troup, and Ms. Grafton, upon separation from WCC, please see the "Potential Payments upon Termination or Change in Control" section of the WCC Proxy Statement.
Other WCC Benefits
Our named executive officers participate in the same basic benefits package and on the same terms as other eligible WCC employees. The benefits package includes the WCC 401(k) Plan described above, as well as medical and dental benefits, disability benefits, insurance (life, travel and accident), death benefits and vacations and holidays. WCC also provides executive physicals and additional long-term disability benefits to certain named executive officers.
For additional detailed information regarding the compensatory plans, agreements and programs of WCC in which our named executive officers participate, we encourage you to read the WCC Proxy Statement.
WESTMORELAND RESOURCE PARTNERS, LP AND SUBSIDIARIES
Compensation Committee Interlocks and Insider Participation
Robert T. Clutterbuck, Jennifer S. Grafton and Kevin A. Paprzycki served as the members of the Compensation Committee through February 24, 2016. Mr. Clutterbuck served as the chairman of the Compensation Committee. The Board of our general partner dissolved the Compensation Committee on February 24, 2016, as all of the Partnership's executives are employed by WCC and all executive compensation decisions are made by the board of WCC.
Compensation Policies and Practices as They Relate to Risk Management
We do not have any employees. We are managed and operated by the directors and officers of our general partner and employees of WCC perform services on our behalf. We do not have any compensation policies or practices that need to be assessed or evaluated for the effect on our operations. For an analysis of any risks arising from WCC's compensation policies or practices, please read the WCC Proxy Statement.
Board Report on Compensation
We have reviewed and discussed with management certain compensation discussion and analysis provisions to be included in this Annual Report on Form 10-K for the year ended December 31, 2016 to be filed pursuant to Section 13(a) of the Securities and Exchange Act of 1934, or this Annual Report on Form 10-K. Based on that review and discussion, we recommend to the Board that the compensation discussion and analysis provisions be included in this Annual Report on Form 10-K.
Kevin A. Paprzycki
Jennifer S. Grafton
Charles C. Ungurean
Gerald A. Tywoniuk
Kurt D. Kost
Keith D. Horton
Robert T. Clutterbuck
Compensation of Directors
Our general partner’s non-employee directors were compensated for their service as directors under our general partner’s Outside Director Compensation Plan reviewed and approved by the Board on March 3, 2017, to be effective as of January 1, 2017. Our non-employee directors for purposes of the plan were directors that (i) were not an officer or employee of our general partner or any of its subsidiaries or affiliates, (ii) were not affiliated with or related to any party that receives compensation from our general partner or any of its subsidiaries and affiliates, and (iii) had not entered into an arrangement with our general partner or any of its subsidiaries and affiliates to receive compensation from any such entity other than in respect of his services as a member of the Board of Directors. Our Outside Director Compensation Plan is designed to attract experienced and highly qualified individuals. The plan combines cash payments appropriate for their commitment and contributions to us and our unitholders, and equity awards to align the interests of the outside directors and unitholders. In addition, in 2016 our general partner’s outside directors were reimbursed for their travel and direct costs associated with membership on the Board. Each outside director covered by the plan received an annual compensation package consisting of the following:
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a cash retainer of $60,000;
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an annual unit grant having a value of $50,000; and
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an Audit Committee chair retainer of $10,000 and an Audit Committee member retainer of $5,000.
Director Compensation Table for 2016
The following table sets forth the compensation paid to our non-employee directors for the year ended December 31, 2016, as described above. Each of our non-employee directors were granted phantom unit equity awards on March 2, 2016.
WESTMORELAND RESOURCE PARTNERS, LP AND SUBSIDIARIES
1 The amounts in this column represent the fees paid to the directors in 2016. All of the fees were paid in cash.
2 The amounts in this column represent the value of unit awards made to directors under our Original LTIP in 2016. For each of the directors, 12,756 units were granted on March 2, 2016, and vested on March 2, 2017, and the units' market value is based on the average closing price of $3.92 per unit at the grant date.
WESTMORELAND RESOURCE PARTNERS, LP AND SUBSIDIARIES
Item 12.
Item 12. Security Ownership of Certain Beneficial Owners and Management and Related Unitholder Matters
The following table sets forth certain information regarding the beneficial ownership of units as of March 10, 2017 (the “Ownership Reference Date”) by:
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each person who is known to us to beneficially own 5% or more of such units to be outstanding;
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our general partner;
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each of the directors and named executive officers of our general partner; and
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all of the directors and executive officers of our general partner as a group.
All information with respect to beneficial ownership has been furnished by the respective directors, officers or 5% or more unitholders as the case may be. Our general partner is owned by WCC.
The amounts and percentage of units beneficially owned are reported on the basis of regulations of the SEC governing the determination of beneficial ownership of securities. Under the rules of the SEC, a person is deemed to be a “beneficial owner” of a security if that person has or shares “voting power,” which includes the power to vote or to direct the voting of such security, or “investment power,” which includes the power to dispose of or to direct the disposition of such security. In computing the number of common units beneficially owned by a person and the percentage ownership of that person, common units subject to options, warrants, convertible security or right, held by that person that are currently exercisable or exercisable within 60 days of the Ownership Reference Date, if any, are deemed outstanding, but are not deemed outstanding for computing the percentage ownership of any other person. Except as indicated by footnote, the persons named in the table below have sole voting and investment power with respect to all units shown as beneficially owned by them, subject to community property laws where applicable.
The percentage of units beneficially owned is based on a total of 1,284,840 common units, 16,215,029 Series A Units and 4,512,500 Series B Units outstanding as of the Ownership Reference Date.
*An asterisk indicates that the person or entity owns less than one percent.
1 The address for this person or entity is 9540 South Maroon Circle, Suite 300, Englewood, Colorado 80112.
WESTMORELAND RESOURCE PARTNERS, LP AND SUBSIDIARIES
2 WCC is the beneficial owner of 35,291 GP unit limited partner interests through its control of our general partner, which we do not include in the calculation of WCC's common unit beneficial ownership, and 55,519 limited partner interests through its ownership of certain common unit warrant rights. WCC owns 100% of the Series A Convertible units, which are convertible to Common Units on a one-for-one basis at the earlier of WMLP declaring a dividend of $0.22 per unit or a change of control. WCC owns 100% of the Series B Convertible Units, which are convertible into Common Units on a one-for-one basis, (i) at the option of the holder, the day after the record date for a cash distribution on the Common Units in which WMLP is unable to make such a distribution without exceeding its restricted payment basket under either of its Financing Agreement or its Revolving Credit Facility, or upon (ii) a change of control, liquidation event or dissolution of the WMLP.
3 All of these common units are owned by a trust established and trusteed by Mr. Clutterbuck. Mr. Clutterbuck disclaims beneficial ownership of the units held by such trust, except to the extent of any pecuniary interest therein.The address for this person or entity is 9540 South Maroon Circle, Suite 300, Englewood, Colorado 80112.
4 All of these common units are owned by a trust established and trusteed by Mr. Horton and his wife. Mr. Horton disclaims beneficial ownership of the units held by such trust, except to the extent of any pecuniary interest therein. The address for this person or entity is 9540 South Maroon Circle, Suite 300, Englewood, Colorado 80112.
5 All of these common units are owned by a trust established and trusteed by Mr. Tywoniuk. Mr. Tywoniuk disclaims beneficial ownership of the units held by such trust, except to the extent of any pecuniary interest therein. The address for this person or entity is 9540 South Maroon Circle, Suite 300, Englewood, Colorado 80112.
6 The address for this person or entity is 9540 South Maroon Circle, Suite 300, Englewood, Colorado 80112. A total of 30,074 of these common units are owned by C&T Coal, Inc. Mr. Ungurean, as a shareholder of C&T Coal, Inc., shares voting and investment power with respect to the common units owned by C&T Coal, Inc. Mr. Ungurean disclaims beneficial ownership of the units, except to the extent of any pecuniary interest therein.
Securities Authorized for Issuance under Equity Compensation Plans
The following table provides information concerning common units that may be issued under our LTI Plans. Our Original LTIP was adopted in connection with the Partnership's initial public offering and amended on or about February 27, 2014, as the result of a Schedule 14C filed with the SEC February 4, 2014. Our LTIP allows for awards of options, phantom units, restricted units, unit awards, other unit awards and unit appreciation rights. It currently permits the grant of awards covering an aggregate of 233,840 units. In October 2016, by consent of our majority unitholder, we adopted the New LTIP that permits the grant of awards covering the aggregate of an additional 500,000 units pursuant to a Schedule 14C filed with the SEC October 24, 2016. Our LTI Plans are administered by the Board of our general partner.
The Board of our general partner in its discretion may terminate, suspend or discontinue our LTI Plans at any time with respect to any award that has not yet been granted. The Board of our general partner also has the right to alter or amend our LTI Plans or any part of either of our LTI Plans from time to time, including increasing the number of units that may be granted subject to unitholder approval as required by the exchange upon which the common units are listed at that time. However, no change in any outstanding grant may be made that would materially impair the rights of the participant without the consent of the participant.
The following table summarizes the number of securities that remained available for future issuance under our LTI Plans as of December 31, 2016.
1 Our Original LTIP was approved by our partners (general and limited) prior to our initial public offering, and amended in February of 2014. Our New LTIP was approved by our partners (general and limited) by consent of our majority unitholder in October of 2016. As of December 31, 2016, our LTI Plans permit the grant of awards covering an aggregate of 503,360 units, inclusive of prior award grants, which grants did not require approval by our limited partners.
WESTMORELAND RESOURCE PARTNERS, LP AND SUBSIDIARIES
Item 13.
Item 13. Certain Relationships and Related Transactions, and Director Independence
At March 10, 2017, WCC owns 100% of our GP and, as of the date of this filing, 93.72% of our limited partner interests on a fully diluted basis. As such, WCC also appoints all of the directors of our general partner.
Distributions and Payments to Our General Partner and Its Affiliates
The following table summarizes the distributions and payments to be made by us to our general partner and its affiliates in connection with our ongoing operations and liquidation. These distributions and payments were determined by and among affiliated entities, and, consequently, are not the result of arm’s-length negotiations.
Relationship with WCC
WCC owns 100% of our sole general partner, Westmoreland Resources GP, LLC, and appoints the members of our Board of Directors and Audit and Conflicts Committees. In addition to the 0.16% general partner interest in us, our general partner owns the incentive distribution rights, which entitle the holder to increasing percentages, up to a maximum of 48% of the cash we distribute in excess of $0.2000 per quarter. As of the time of this filing, WCC also owns 94.17% of our outstanding beneficial equity interests.
Services Agreement
Effective January 1, 2015, we entered into an administrative and operational services agreement ("Services Agreement") with our general partner. We amended the Services Agreement on October 23, 2015, to modify the amount of the fixed annual fee that we pays our general partner for the services provided pursuant to the Services Agreement to reflect increased costs associated with the Kemmerer Drop. Under the Services Agreement, our general partner provides services to us and is reimbursed for related costs incurred on our behalf. The services that our general partner provides include, among other things, operating services, engineering services and general and administrative services, including but not limited to legal, accounting, treasury, insurance administration and claims processing, risk management, health, safety and environmental, information technology, human resources, credit, payroll, internal audit, taxes and engineering services. Where costs are specifically incurred on behalf of one of our affiliates, the costs are billed directly to us by WCC. Costs may also be allocated to us in a variety of methods when a cost or service applies equally to all employees. Additionally, the Services Agreement provides for an annual fixed fee to reimburse our general partner for executive officers and other employees who devote less than a majority of their time to us. During 2016, we paid our general partner approximately $71.2 million for services performed under the Services Agreement. Any party may terminate the Services Agreement by providing at least 30 days’ written notice to the other parties.
WESTMORELAND RESOURCE PARTNERS, LP AND SUBSIDIARIES
Procedures for Review, Approval and Ratification of Related Person Transactions
The Board of Directors of our general partner has adopted a code of business conduct and ethics that provides that the Board of Directors of our general partner or its authorized committee will periodically review all related person transactions that are required to be disclosed under SEC rules and, when appropriate, initially authorize or ratify all such transactions. In the event that the Board of Directors of our general partner or its authorized committee considers ratification of a related person transaction and determines not to so ratify, the code of business conduct and ethics provides that our management will make all reasonable efforts to cancel or annul the transaction.
The code of business conduct and ethics provides that, in determining whether or not to recommend the initial approval or ratification of a related person transaction, the Board of Directors of our general partner or its authorized committee should consider all of the relevant facts and circumstances available, including (if applicable) but not limited to: (i) whether there is an appropriate business justification for the transaction; (ii) the benefits that accrue to us as a result of the transaction; (iii) the terms available to unrelated third parties entering into similar transactions; (iv) the impact of the transaction on a director’s independence (in the event the related person is a director, an immediate family member of a director or an entity in which a director or an immediately family member of a director is a partner, shareholder, member or executive officer); (v) the availability of other sources for comparable products or services; (vi) whether it is a single transaction or a series of ongoing, related transactions; and (vii) whether entering into the transaction would be consistent with the code of business conduct and ethics. Additionally, to further structure and facilitate such transactions, the Board of our general partner adopted a related party transactions policy that allows for standing pre-approval of certain transactions and approval by our independent audit committee chairman for related party transactions within certain parameters.
The code of business conduct and ethics described above was reaffirmed and adopted on October 20, 2015. Copies of the code of business conduct and ethics, and our related party transactions policy, can be found at www.westmorelandMLP.com in the Investor Relations/Corporate Governance section. Additionally a unitholder may make such a request in writing by mailing such request to Investor Relations, Westmoreland Resource Partners, LP, 9540 South Maroon Circle, Suite 300, Englewood, CO 80112, or by emailing such request to Investor Relations at ir@westmoreland.com.
Further information required for this item is provided in Item 1 - Business - Overview, Item 10 - Directors, Executive Officers and Corporate Governance and Note 24. Related Party Transactions to the consolidated financial statements.
Director Independence
Our disclosures in Item 10 - Directors, Executive Officers and Corporate Governance are incorporated herein by reference.
WESTMORELAND RESOURCE PARTNERS, LP AND SUBSIDIARIES
Item 14.
Item 14. Principal Accountant Fees and Services
The following table sets forth fees and out-of-pocket expenses billed by our principal accountant for the audit of our annual financial statements and other services rendered for the fiscal years ended December 31, 2016 and 2015:
1 Includes fees and expenses for audits of annual financial statements of our subsidiaries, reviews of the related quarterly financial statements, services related to testing our internal controls over financial reporting and services that are normally provided by the independent accountants in connection with statutory and regulatory filings or engagements, including reviews of documents filed with the SEC.
2 On March 10, 2015 we approved the appointment of Ernst & Young LLP as the Partnership’s independent registered public accounting firm for the fiscal year ending December 31, 2015, which effectively dismissed Grant Thornton LLP as the Partnership’s independent registered public accounting firm as of March 10, 2015. In 2015, Audit Fees from Ernst & Young LLP included a re-audit of the 2014 financial statements as a result of the Kemmerer Drop being categorized as a business combination under common control. See Note 3. Acquisition And Pushdown Accounting to the consolidated financial statements.
Pursuant to the charter of the Audit Committee, the Audit Committee is responsible for the oversight of our accounting, reporting and financial practices. The Audit Committee is responsible for the appointment, compensation, retention and oversight of the work of our external auditors; the pre-approval of all audit and non-audit services to be provided, consistent with all applicable laws, to us by our external auditors; and the establishment of the fees and other compensation to be paid to our external auditors. The Audit Committee also oversees and directs our internal auditing program and reviews our internal controls.
The Audit Committee has adopted a policy for the pre-approval of audit and permitted non-audit services provided by our principal independent accountants. The policy requires that all services provided by Ernst & Young LLP, including audit services, audit-related services, and other services, must be pre-approved by the Audit Committee.
The Audit Committee reviews the external auditors’ proposed scope and approach as well as the performance of the external auditors. It also has direct responsibility for resolution of and sole authority to resolve any disagreements between our management and our external auditors regarding financial reporting, regularly reviews with the external auditors any problems or difficulties the auditors encounter in the course of their audit work, and, at least annually, uses its reasonable efforts to obtain and review a report from the external auditors addressing the following (among other items):
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the external auditors’ internal quality-control procedures;
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any material issues raised by the most recent internal quality-control review, or peer review, of the external auditors;
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the independence of the external auditors;
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the aggregate fees billed by the external auditors for each of the previous two fiscal years; and
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the rotation of the external auditors’ lead partner.
WESTMORELAND RESOURCE PARTNERS, LP AND SUBSIDIARIES
PART IV
Item 15.
Item 15. Exhibits and Financial Statement Schedules
(a)1.Financial Statements. See “Index to Financial Statements” on page.
(a)2.Financial Statement Schedules. Other schedules are omitted because they are not required or applicable, or the required information is included in our consolidated financial statements or related notes.
(a)3.Exhibits. See “Index to Exhibits.”
Item 16. Form 10K Summary
None.
Westmoreland Resource Partners, LP and Subsidiaries
F- 1
REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
Board of Directors and Unitholders of
Westmoreland Resource Partners, LP
We have audited the accompanying consolidated balance sheets of Westmoreland Resource Partners, LP (the “Partnership”) as of December 31, 2016 and 2015, and the related consolidated statements of operations, comprehensive loss, partners’ capital (deficit), and cash flows for each of the two years in the period ended December 31, 2016 and the period ended December 31, 2014 (Successor) and the related consolidated statements of operations, comprehensive loss, partners’ capital (deficit), and cash flows of Oxford Resource Partners, LP for the period from January 1, 2014 through December 31, 2014 (Predecessor). These consolidated financial statements are the responsibility of the Partnership's management. Our responsibility is to express an opinion on these consolidated 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 consolidated financial statements are free of material misstatement. We were not engaged to perform an audit of the Partnership’s internal control over financial reporting. Our audits included consideration of internal control over financial reporting as a basis for designing audit procedures that are appropriate in the circumstances, but not for the purpose of expressing an opinion on the effectiveness of the Partnership’s internal control over financial reporting. Accordingly, we express no such opinion. An audit also includes examining, on a test basis, evidence supporting the amounts and disclosures in the consolidated financial statements, assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall consolidated 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 Resource Partners, LP as of December 31, 2016 and 2015, and the consolidated results of its operations and its cash flows for each of the two years in the period ended December 31, 2016 and the period of December 31, 2014 (Successor), and the related consolidated statements of operations, comprehensive loss, partners’ capital (deficit), and cash flows of Oxford Resource Partners, LP for the period from January 1, 2014 through December 31, 2014 (Predecessor), in conformity with U.S. generally accepted accounting principles.
/s/ Ernst & Young LLP
Grandview Heights, Ohio
March 16, 2017
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WESTMORELAND RESOURCE PARTNERS, LP AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEETS
(In thousands)
See accompanying notes to consolidated financial statements.
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WESTMORELAND RESOURCE PARTNERS, LP AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEETS
(In thousands)
See accompanying notes to consolidated financial statements.
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WESTMORELAND RESOURCE PARTNERS, LP AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF OPERATIONS
(In thousands, except for per unit data)
(1)See Note 3. Acquisition And Pushdown Accounting to the consolidated financial statements.
See accompanying notes to consolidated financial statements.
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WESTMORELAND RESOURCE PARTNERS, LP AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF COMPREHENSIVE LOSS
(In thousands)
See accompanying notes to consolidated financial statements.
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WESTMORELAND RESOURCE PARTNERS, LP AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF PARTNERS’ CAPITAL (DEFICIT)
(In thousands, except for unit data)
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See accompanying notes to consolidated financial statements.
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WESTMORELAND RESOURCE PARTNERS, LP AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF CASH FLOWS
(In thousands)
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See accompanying notes to consolidated financial statements.
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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
1. ORGANIZATION AND PRESENTATION
Basis of Presentation and Principles of Consolidation
The accompanying consolidated financial statements include the accounts and operations of the Westmoreland Resource Partners, LP, or the "Partnership," and its consolidated subsidiaries and are prepared in conformity with GAAP. WCC's cost of acquiring our GP has been pushed-down to establish a new accounting basis for us beginning in the last minutes of the year ended December 31, 2014. Accordingly, certain accompanying consolidated financial statements are presented for two periods, Predecessor and Successor, which relate to the accounting periods preceding and succeeding the completion of the transaction. The Predecessor and Successor periods have been separated by a vertical line on the face of the consolidated financial statements to highlight the fact that the financial information for such periods has been prepared under two different historical-cost bases of accounting.
Significant Relationships Referenced in Notes to Consolidated Financial Statements
•
“We,” “us,” “our,” “WMLP,” and the “Partnership” means the business and operations of Westmoreland Resource Partners, LP as well as its consolidated subsidiaries.
•
“GP” means Westmoreland Resources GP, LLC, the General Partner of Westmoreland Resource Partners, LP.
Acquisition of Oxford Resources GP, LLC
On December 31, 2014, pursuant to a Purchase Agreement dated October 16, 2014, WCC acquired, for $33.5 million in cash, 100% of the equity of our GP from (i) the holders of all of our GP’s outstanding Class A Units, AIM Oxford Holdings, LLC ("AIM") and C&T Coal, Inc ("C&T"), (ii) the holders of all of our GP’s outstanding Class B Units, certain present and former executives of our GP, and (iii) the holders of all of the outstanding warrants for our GP’s Class B Units, the Warrantholders. At the same time, WCC also acquired, for no additional consideration, (i) 100% of the Partnership’s outstanding subordinated units from AIM and C&T, which subordinated units were then converted to liquidation units, and (ii) 100% of the Partnership’s outstanding warrants for subordinated units from the Warrantholders, which warrants were then canceled by WCC. Please refer to Note 3. Acquisition And Pushdown Accounting to the consolidated financial statements.
Contribution of Kemmerer Mine Fee Coal Reserves
On December 31, 2014, pursuant to a Contribution Agreement dated October 16, 2014, WCC contributed to us 100% of the membership interests in Westmoreland Kemmerer Fee Coal Holdings, LLC (“WKFCH”). WKFCH held fee simple interests in 30.4 million tons of coal reserves and related surface lands at WCC’s Kemmerer mine in Lincoln County, Wyoming. Such contribution was made in exchange for 4,512,500 post-reverse split common units.
In connection with this contribution, WKFCH entered into a coal mining lease with respect to these coal reserves with a subsidiary of WCC pursuant to which we will earn a per ton royalty as these coal reserves are mined. Through the coal leasing arrangement, the mining of the Kemmerer mine fee coal reserves will generate minimum royalty payments of $1.0 million per quarter from the start of 2015 through December 31, 2020 and $0.5 million per quarter thereafter through December 31, 2025.
WCC's Contribution of Westmoreland Kemmerer, LLC
On August 1, 2015, WCC, who owns and controls the GP, contributed 100% of the outstanding equity interests in Westmoreland Kemmerer, LLC ("WKL") to the Partnership in exchange for $230 million in aggregate consideration, composed of $115 million of cash and 15,251,989 Series A Convertible Units of the Partnership (“Series A Units”) with a value of $115 million (the “Kemmerer Drop”). The Kemmerer Drop was accounted for as a reorganization of entities under common control in accordance with the provisions of Accounting Standards Codification (“ASC”) 805-50, which requires that the transaction be presented as though it occurred at the beginning of the period, and prior years retrospectively adjusted to furnish comparative information similar to the pooling method. Accordingly, our financial statements give retrospective effect to the Kemmerer Drop for periods as of and subsequent to December 31, 2014, the earliest point of common control.
The contribution of net assets of WKL was accounted for as a transaction between entities under common control whereby the WKL was recorded at historical book value. As such, the cash consideration paid in excess of the net assets
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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
contributed by WCC amounted to $13.2 million. The amount of the cash purchase price in excess of WCC’s basis in the net assets is recognized as a reduction of partners’ equity. The financial statements of WKL have been prepared from the separate records maintained by WCC and may not necessarily be indicative of the conditions that would have existed or the results of operations if WKL had been operated as an unaffiliated entity during the periods reported.
Immediately prior to the Kemmerer Drop and in accordance with the Amended and Restated Contribution Agreement, dated July 31, 2015, between the Partnership and WCC (the “Contribution Agreement”) all employees of WKL were transferred to WCC. WCC assumed all liabilities, including the pension plan assets, associated with the transferred employees, including but not limited to all post-retirement pension, medical, other benefits and the related deferred income tax assets and liabilities, which were not contributed as part of the transaction (the “Excluded Liabilities”).
For periods prior to August 1, 2015, WKL files consolidated federal and state income tax returns with WCC. As WKL itself is not a taxable entity, WCC’s income tax expense for its income tax return group included on WCC’s consolidated income tax return is allocated among the members of that group. This allocation is calculated as if each member were a separate taxpayer. This allocation is reflected by WKL in Income tax expense with the offset in Shareholder's equity. There is no formal tax sharing agreement with WCC.
For periods prior to August 1, 2015, WKL accounts for deferred income taxes using the asset and liability method. Deferred income tax liabilities and assets are recognized for the expected future tax consequences of events that have been reflected in WKL’s financial statements based on the difference between the financial statement carrying amounts and tax bases of assets and liabilities, as well as net operating loss and tax credit carry-forwards, using enacted tax rates in effect in the years in which the differences are expected to reverse. WKL establishes a valuation allowance against its net deferred tax assets to the extent WKL believes that it is more likely than not (greater than 50%) that a deferred income tax asset will not be realized.
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 derecognition, classification, interest and penalties, accounting in interim periods, disclosure and transition. WKL includes interest and penalties related to income tax matters in income tax expense.
The financial statements of the Partnership, for all periods presented, and WKL, for periods subsequent to August 1, 2015, contained herein are based on the assumption that the Partnership will continue to be treated as a partnership for U.S. federal and state income tax purposes and therefore will not be subject to U.S. federal income taxes or state income taxes.
Our net investment column presented within the Statement of Partner’s Capital (Deficit) consists of the equity related transactions of WKL for the 2015 period prior to the Kemmerer Drop and in connection with the Kemmerer Drop. Accordingly, our consolidated financial statements include the historical results of WKL for all periods subsequent to December 31, 2014. The amount of the purchase price in excess or in deficit of WCC’s basis in the net assets is recognized as a reduction or an addition to limited partners’ and general partners’ capital. The financial statements of WKL have been prepared from separate records maintained by WCC and may not necessarily be indicative of the conditions that would have existed or the results of operations if WKL had been operated as an unaffiliated entity during the periods reported.
Please refer to Note 3. Acquisition And Pushdown Accounting to the consolidated financial statements.
Series A Convertible Common Limited Partnership Units
In connection with the Kemmerer Drop and the issuance of the Series A Units, the Partnership entered into an amendment (the “Amendment”) to our fourth amended and restated partnership agreement, as amended (the "Partnership Agreement"). The Amendment established the terms of the Series A Convertible Units and any additional Series A Convertible Units that may be issued in kind as a distribution (the “Series A PIK Units”), and provided that each Series A Convertible Unit will have the right to share in distributions from us on a pro rata basis with the common units. All or any portion of each distribution payable in respect of the Series A Convertible Units (the “Series A Convertible Unit Distribution”) may, at our election, be paid in Series A PIK Units. To the extent any portion of the Series A Convertible Unit Distribution is paid in Series A PIK Units for any quarter, the distribution to the holders of incentive distribution rights shall be reduced by that portion of the distribution that is attributable to the payment of those Series A PIK Units, as further described in the Amendment. The Series A Convertible Units and the Series A PIK Units will convert into common units at the earlier of the first anniversary of the initial issuance of the Series A Convertible Units, the date on which we first make a regular quarterly cash distribution with respect to
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WESTMORELAND RESOURCE PARTNERS, LP AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
any quarter to holders of common units in an amount at least equal to $0.22 per common unit or upon a change of control. The Series A Convertible Units have the same voting rights as if they were outstanding common units and will vote together with the common units as a single class. In addition, the Series A Convertible Units are entitled to vote as a separate class on any matters that materially adversely affect the rights or preferences of the Series A Convertible Units in relation to other classes of partnership interests or as required by law.
Series B Convertible Units
On October 28, 2016, we issued 4,512,500 Series B Convertible Units representing limited partner interests in the Partnership (the “Series B Units”) to WCC in exchange for WCC’s 4,512,500 common units (the “Exchange”). Upon issuance of the Series B Units in the Exchange, WCC’s common units were canceled. The Series B Units do not share in distributions with the common units and are convertible at the option of the holder on a one-for-one basis into common units on the day after the record date for a cash distribution on the common units in which the Partnership is unable to make such a distribution without exceeding its restricted payment basket under the 2014 Financing Agreement (as defined in Note 13. Long-Term Debt to the consolidated financial statements). The Series B Units will convert automatically upon a change of control or a dissolution or liquidation of the Partnership. The Series B Units have the same voting rights as if they were outstanding common units and will vote together with the common units as a single class. In addition, the Series B Units are entitled to vote as a separate class on any matters that materially adversely affect the rights or preferences of the Series B Units in relation to other classes of partnership interests or as required by law. Concurrently with the Exchange, we entered into Amendment No. 2 to the Partnership Agreement, which established aforementioned terms of the Series B Units.
Organization
See Item 1 - Business - Overview.
2. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES
Use of Estimates
The preparation of financial statements in conformity with 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.
Purchase and Pushdown Accounting
WCC's acquisition of our GP was accounted for using the acquisition method under ASC 805, Business Combination. Under the acquisition method, the purchase price was allocated to the underlying tangible and intangible assets acquired and liabilities assumed based on their respective fair values. The allocation of the purchase price is pending the completion of various analyses and the finalization of estimates. During the measurement period (which is not to exceed one year from the acquisition date), additional assets or liabilities may be recognized if new information is obtained about facts and circumstances that existed as of the acquisition date that, if known, would have resulted in the recognition of those assets or liabilities as of that date. The allocation may be adjusted after obtaining additional information regarding, among other things, asset valuations, liabilities assumed and revisions of previous estimates. These adjustments may be significant and will be accounted for retrospectively.
Per ASC 805-50-25-4 (effective November 18, 2014), we, as an acquiree of WCC through our GP, have the option to apply pushdown accounting in our consolidated financial statements when an acquirer (WCC) obtained control of us. We have chosen to adopt pushdown accounting and will reflect purchase accounting adjustments in our consolidated financial statements.
Drop-down Accounting
Drop-down acquisitions with WCC, our ultimate parent, are accounted for as a reorganization of entities under common control in accordance with the provisions of Accounting Standards Codification (“ASC”) 805-50, which requires that the transaction be presented as though it occurred at the beginning of the period, and prior years retrospectively adjusted to furnish comparative information similar to the pooling method. Accordingly, our financial statements give retrospective effect of drop-down acquisitions for periods as of and subsequent to December 31, 2014.
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WESTMORELAND RESOURCE PARTNERS, LP AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
Cash and Cash Equivalents
Cash and cash equivalents are stated at cost, which approximate fair value. Cash equivalents consist of highly liquid investments with original maturities of three months or less.
Trade Receivables
Trade receivables are recorded at the invoiced amount and do not bear interest. The Partnership evaluates the need for an allowance for doubtful accounts based on a review of collectability. The Partnership has determined that no allowance is necessary for trade receivables as of December 31, 2016 and 2015.
Inventories
Inventories, which include materials and supplies, as well as raw coal, are stated at the lower of cost or market. Cost is determined using the average cost method. Coal inventory costs include labor, supplies, equipment, depreciation, depletion, amortization, operating overhead and other related costs.
Exploration and Mine Development
Exploration expenditures are charged to Cost of coal revenues as incurred, including costs related to drilling and study costs incurred to convert or upgrade mineral resources to reserves.
At existing surface mines, additional pits may be added to increase production capacity. These expansions may require significant capital to purchase or relocate equipment, build or improve existing haul roads and create the initial cut to remove overburden for new pits at existing mines. 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 Partnership 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 or fair value as a result of purchase accounting as previously discussed. 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 and application of pushdown accounting.
Coal reserves, mineral rights and mine development costs are depleted based upon estimated proven and probable reserves. Plant and equipment are depreciated on a straight-line basis over the assets’ estimated useful lives as follows:
We assess the carrying value of our property, plant and equipment for impairment whenever events or changes in circumstances indicate that the carrying amount of an asset may not be recoverable. Recoverability is measured by comparing estimated undiscounted cash flows expected to be generated from such assets to their net book value. If net book value exceeds estimated cash flows, the asset is written down to fair value. When an asset is retired or sold, its cost and related accumulated depreciation and depletion are removed from the accounts. The difference between the net book value of the asset and proceeds on disposition is recorded as a gain or loss. Fully depreciated plant and equipment still in use is not eliminated from the accounts. Amortization of capital leases is included in Depreciation, depletion and amortization.
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WESTMORELAND RESOURCE PARTNERS, LP AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
Advanced Coal Royalties
A portion of our reserves are leased. Advanced coal royalties are advance payments made to lessors under terms of lease agreements that are typically recoupable through an offset or credit against royalties payable on future production. We write-off advanced coal royalties when recoverability is no longer probable based on future mining plans.
Restricted investments and bond collateral
Restricted investments and bond collateral consist of cash and available-for-sale fixed-income investments reported at fair value with unrealized gains and losses excluded from earnings and reported in Accumulated other comprehensive loss. Funds in the restricted investments and bond collateral accounts are not available to meet the Partnership’s general cash needs.
Deferred Financing Costs
We capitalize 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 Deposits and other assets in the accompanying consolidated balance sheets.
Financial Instruments
The Partnership 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 loss in partners' capital (deficit).
Our financial instruments include fixed price forward contracts for diesel fuel. Our risk management policy allows us to purchase up to 80% of our unhedged diesel fuel gallons on fixed price forward contracts. These contracts meet the normal purchases and sales exclusion and therefore are not accounted for as derivatives. These forward fuel contracts usually have a term of 1 year or less, and we take physical delivery of all the fuel supplied under these contracts.
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.
The Partnership determines the estimated fair value of its asset retirement obligations by calculating the present value of estimated cash flows related to reclamation liabilities using Level 3 inputs. The significant inputs used to calculate such liabilities includes estimates of costs to be incurred, the Partnership’s credit adjusted discount rate, inflation rates and estimated dates of reclamation. The asset retirement liability is accreted to its present value each period and the associated mineral rights are depleted using the units-of-production method.
The fair value of assets and liabilities acquired through business combinations is calculated using a discounted-cash flow approach using Level 3 inputs. Cash flow estimates require forecasts and assumptions for many years into the future for a variety of factors.
See Note 6. Restricted Investments And Bond Collateral, Note 7. Postretirement Medical Benefits, Note 8. Pension And Other Saving Plans, Note 12. Asset Retirement Obligations, and Note 14. Fair Value Measurements to the consolidated financial statements for further disclosures related to the Partnership’s fair value estimates.
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WESTMORELAND RESOURCE PARTNERS, LP AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
Warrants
In connection with our refinancing in June 2013, certain of the second lien lenders and lender affiliates received warrants entitling them to purchase common and subordinated units under a freestanding contract. The subordinated unit warrants were canceled on December 31, 2014. Pursuant to Financial Accounting Standards Board's Codification Topic 470-20, “Debt With Conversion and Other Options” (ASC 470-20), freestanding contracts that are settled in a company’s own stock, including common and subordinated unit warrants, are to be designated as an asset, liability or equity instrument. Both the common and subordinated unit warrants were determined to be liabilities and were recorded at fair value.
Intangible Assets
Identifiable intangible assets acquired in a business combination must be recognized and reported separately from goodwill. These intangible assets are amortized on a straight-line basis over the respective useful life of the asset. See Note 10. Intangible Assets to the consolidated financial statements for further details.
Deferred Revenue
Deferred revenues represent funding received upon the negotiation of long-term contracts. The deferred revenues for coal will be recognized as deliveries of the reserved coal are made in accordance with the long-term coal contracts. At December 31, 2016 and 2015, deferred revenue was $3.5 million and zero, respectively.
Asset Retirement Obligations
Our asset retirement obligations, or ARO, primarily consists of estimated costs to reclaim surface land and support facilities at our mines and in accordance with federal and state reclamation laws as established by each mining permit.
We estimate ARO for final reclamation and mine closure based upon detailed engineering calculations of the amount and timing of the future costs for a third party to perform the required work. These estimates are based on projected pit configurations at the end of mining and are escalated for inflation, and then discounted at a credit adjusted risk-free rate. We record mineral rights associated with the initial recorded liability. Mineral rights are amortized based on the units of production method over the estimated proven and probable reserves at the related mine, and the ARO 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. See Note 12. Asset Retirement Obligations to the consolidated financial statements.
Income Taxes
As a partnership, we are not a taxable entity for federal or state income tax purposes; the tax effect of our activities passes through to our unitholders. Therefore, no provision or liability for federal or state income taxes is included in our financial statements. Net income (loss) for financial statement purposes may differ significantly from taxable income (loss) reportable to our unitholders as a result of timing or permanent differences between financial reporting under US GAAP and the regulations promulgated by the Internal Revenue Service.
Prior to the Kemmerer Drop, WKL was subject to income taxes in the U.S. (including federal and state). Deferred income taxes were 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, WKL considered 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.
WKL includes interest and penalties related to income tax matters in income tax expense, however there were no interest
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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
and penalties for the year ended December 31, 2016.
Revenue Recognition
The Partnership recognizes coal sales revenue at the time title passes to the customer in accordance with the terms of the underlying sales agreements. The point that title passes varies by agreement. Under our sales agreements title transfer points include upon loading to truck or rail, upon delivery by truck or rail, upon loading to conveyor belt, upon delivery from conveyor belt, and upon delivery to stockpile. Coal sales revenue is recognized based on the pricing contained in the contracts in place at the time that title passes.
Royalty revenue relates to coal reserves which we lease to others and oil and gas rights. For the years ended 2016, 2015 and 2014, we received royalties of $0.9 million, $0.9 million and $0.3 million, respectively.
Non-coal revenue consists primarily of clay and limestone sales, service fees, and other miscellaneous revenue. Clay and limestone sales relate to material we recover during the coal mining process and sell to third parties. Additionally service fees are earned for operating a coal unloading facility, providing river barge loading services, and hauling ash. Periodically, we recognize miscellaneous revenue related to lost coal claims that result from granting third-party right-of-way access through small portions of various mine complexes. In 2014, we also received $19.5 million from a former customer to compensate us for lost profits on a wrongfully terminated contract.
Equity-Based Compensation
Equity-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 coal revenues and Selling and administrative in the accompanying consolidated results of operations. See Note 16. Long-Term Incentive Plan to the consolidated financial statements.
Noncontrolling Interest
Noncontrolling interest is reported as a separate component of equity. The amount of net income (loss) attributable to the noncontrolling interest is recorded in Net income (loss) attributable to noncontrolling interest in our Consolidated Statements of Operations. See Note 18. Noncontrolling Interest to the consolidated financial statements.
Earnings (Losses) Per Unit
For purposes of our earnings per unit calculation, we apply the two class method. All outstanding limited partner units and general partner units share pro rata in income (loss) allocations and distributions, but only our general partner has voting rights. Limited partner units are further segregated into common units and subordinated units. As of December 31, 2014, the subordinated units were converted to liquidation units.
Limited Partner Units: Basic earnings (losses) per unit are computed by dividing net income (loss) applicable to limited partners by the weighted average units outstanding, including unexercised participating warrants, during the reporting period. Net income (loss) applicable to units includes the adjustment for net income or loss attributable to noncontrolling interest. Diluted earnings (losses) per unit are computed similar to basic earnings (losses) per unit except that the weighted average units outstanding and net income (loss) attributable to limited partners are increased to include the dilutive effect of limited partner units that would be issued assuming conversion of restricted awards to limited partnership units upon vesting. No such items were included in the computation of diluted loss per unit for the years ended 2016, 2015 or 2014 because we incurred a loss in each of these periods and the effect of inclusion would have been anti-dilutive.
The table below shows the number of units that were excluded from the calculation of diluted loss per unit because their inclusion would be anti-dilutive to the calculation:
Reclassifications
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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
Certain amounts in prior periods have been reclassified to conform with the presentation of 2016.The reclassification affected accounts within noncurrent assets and liabilities on the Consolidated Balance Sheet.
Recently Adopted Accounting Pronouncements
In April 2015, the Financial Accounting Standards Board (“FASB”) issued Accounting Standards Update (“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 debt liability be presented in the balance sheet as a direct deduction from the carrying amount of that debt liability, consistent with debt discounts. The Partnership adopted this standard on January 1, 2016 and retrospectively applied the guidance to prior periods. The adoption of this standard resulted in the reclassification of $8.0 million of unamortized debt issuance costs from the non-current asset, Deposits and other assets, to a reduction of Long-term debt, less current installments on the consolidated balance sheet as of December 31, 2015.
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 management’s responsibility to evaluate whether there is substantial doubt about an entity’s ability to continue as a going concern and to provide related footnote disclosures if substantial doubt exists. The standard became effective for us for annual and interim periods on December 31, 2016 when we adopted it.
Accounting Pronouncements Effective in the Future
In May 2014, the FASB issued ASU 2014-09, Revenue from Contracts with Customers, issued as a new Topic, ASC Topic 606. The new revenue recognition standard supersedes all existing revenue recognition guidance. Under this ASU, an entity should recognize revenue when it transfers promised goods or services to customers in an amount that reflects the consideration to which the entity expects to be entitled in exchange for those goods or services. ASU 2015-14, issued in August 2015, deferred the effective date of ASU 2014-09 to the first quarter of 2018, with early adoption permitted in the first quarter of 2017. The Partnership intends to adopt the amended guidance as of January 1, 2018.
In March, April, May, and December 2016, the FASB issued the following updates, respectively, to provide supplemental adoption guidance and clarification to ASU 2014-09. These standards must be adopted concurrently upon the adoption of ASU 2014-09. We are currently evaluating the potential effects of adopting the provisions of these updates.
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ASU No. 2016-08, Revenue from Contracts with Customers: Principal versus Agent Considerations (Reporting Revenue Gross versus Net)
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ASU No. 2016-10, Revenue from Contracts with Customers: Identifying Performance Obligations and Licensing;
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ASU No. 2016-12, Revenue from Contracts with Customers: Narrow-Scope Improvements and Practical Expedients; and
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ASU No. 2016-19, Technical Corrections and Improvements
During 2016, the Partnership established an implementation team to develop a multi-phase plan to assess the Partnership's business and contracts, as well as any changes to processes or systems to adopt the requirements of the new standard. The team is in the process of developing its conclusions on several aspects of the standard including principal versus agent considerations, identification of performance obligations and the determination of when control of goods and services transfers to the Partnership's customers.
Under the new standard, companies may use either of the following transition methods: (i) a full retrospective approach reflecting the application of the standard in each prior reporting period with the option to elect certain practical expedients, or (ii) a modified retrospective approach with the cumulative effect of initially adopting ASU 2014-09 recognized at the date of adoption (which includes additional footnote disclosures). We have not concluded which transition method we will elect, but we currently anticipate using the full retrospective approach.
In July 2015, the FASB issued ASU 2015-11, Simplifying the Measurement of Inventory. ASU 2015-11 simplifies the subsequent measurement of inventory by replacing today’s lower of cost or market test with a lower of cost and net realizable value test. The guidance applies only to inventories for which cost is determined by methods other than last-in first-out (LIFO) and the retail inventory method (RIM). Entities that use LIFO or RIM will continue to use existing impairment models (e.g., entities using LIFO would apply the lower of cost or market test). The guidance is effective for public business entities for fiscal years beginning after 15 December 2016, and interim periods within those fiscal years. Early adoption is permitted as of the beginning of an interim or annual reporting period. 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.
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In January 2016, the FASB issued ASU 2016-01, Financial Instruments - Overall (Subtopic 825-10): Recognition and Measurement of Financial Assets and Financial Liabilities. The amendments in this Update address certain aspects of recognition, measurement, presentation, and disclosure of financial instruments. ASU 2016-01 is effective for fiscal years beginning after December 15, 2017, including interim periods within those fiscal years. 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.
In February 2016, the FASB issued ASU 2016-02, Leases (Topic 842) which requires companies leasing assets to recognize on their balance sheet a liability to make lease payments (the lease liability) and a right-of-use asset representing its right to use the underlying asset for the lease term on contracts longer than one year. The lessee is permitted to make an accounting policy election to not recognize lease assets and lease liabilities for short-term leases. How leases are recorded on the balance sheet represents a significant change from previous GAAP guidance in Topic 840. ASU 2016-02 maintains a distinction between finance leases and operating leases similar to the distinction under previous lease guidance for capital leases and operating leases. The impact of leases reported in the Partnership's operating results and statement of cash flows are expected to be similar to previous GAAP.
ASU 2016-02 is effective for fiscal years beginning after December 15, 2018, and early adoption is permitted. Adoption of the new lease accounting standard will require the Partnership to apply the new standard to the earliest period using a modified retrospective approach. The Partnership is currently in the process of evaluating the impact of the new standard, including the evaluation of the impact, if any, on changes to business processes, systems and controls to support recognition and disclosure under the new guidance, however, at this time is unable to determine the impact this standard will have on the financial statements and related disclosures.
In March 2016, the FASB issued ASU 2016-09, Compensation - Stock Compensation (Topic 718): Improvements to Employee Share-Based Payment Accounting. This ASU is designed to address simplification of several aspects of the accounting for share-based payment transactions, including the income tax consequences, classification of awards as either equity or liabilities, and classification on the statement of cash flows. ASU 2016-09 is effective for annual periods beginning after December 15, 2016, and interim periods within those annual periods. Early adoption of this ASU is permitted and would be applied on a retrospective basis back to the beginning of fiscal year that included any such interim period in which early adoption was elected. 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.
In June 2016, the FASB issued ASU 2016-13, Financial Instruments - Credit Losses (Topic 326): Measurement of Credit Losses on Financial Instruments. The amendments within this ASU replace the incurred loss impairment methodology in current GAAP with a methodology that reflects expected credit losses and requires consideration of a broader range of reasonable and supportable information to inform credit loss estimates. ASU 2016-13 is effective for fiscal years beginning after December 15, 2019, including interim periods within those fiscal years. Entities may early adopt the amendments within this ASU but not prior to the fiscal years beginning after December 15, 2018, including the interim periods within those fiscal years. An entity will apply the amendments in this Update through a cumulative-effect adjustment to retained earnings as of the beginning of the first reporting period in which the guidance is effective (that is, a modified-retrospective approach). However, a prospective transition approach is required for debt securities for which an other-than-temporary impairment had been recognized before the effective date. 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.
3. ACQUISITION AND PUSHDOWN ACCOUNTING
WCC's Acquisition of our General Partner
On December 31, 2014, pursuant to a Purchase Agreement dated October 16, 2014, WCC acquired, for $33.5 million in cash, 100% of the equity of our GP from (i) the holders of all of our GP’s outstanding Class A Units, AIM and C&T, (ii) the holders of all of our GP’s outstanding Class B Units, certain present and former executives of our GP, and (iii) the holders of all of the outstanding warrants for our GP’s Class B Units, the Warrantholders. At the same time, WCC also acquired, for no additional consideration, (i) 100% of the Partnership’s outstanding subordinated units from AIM and C&T, which subordinated units were then converted to liquidation units, and (ii) 100% of the Partnership’s outstanding warrants for subordinated units from the Warrantholders, which warrants were then canceled by WCC.
The purchase consideration for our GP and control of our GP’s consolidated subsidiaries is estimated at $239.9 million, which included $33.5 million paid in cash, plus the assumption of approximately $195.6 million of liabilities. Additionally, we
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incurred acquisition-related costs of $5.5 million that have been expensed and are included in Selling and administrative in the accompanying consolidated results of operations for the predecessor period of January 1, 2014 through December 31, 2014.
The acquisition of our GP was accounted for by WCC 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. We have elected to apply pushdown accounting to our consolidated financial statements. By applying pushdown accounting, our financial statements also reflect these adjustments to fair value with a portion allocated to noncontrolling interest for the portion of us that is not owned directly by WCC.
Subsequent to the acquisition of our GP, the following events occurred which are activity of the new owners or Successor entity. The acquisition triggered change of control provisions in the executives’ employment contracts which resulted in additional restructuring expenses. See Note 4. Restructuring And Impairment Charges to the consolidated financial statements. Subsequent to the transaction, we also refinanced our debt which included an early payment penalty included in debt extinguishment costs.
Kemmerer Drop-down
On August 1, 2015, we completed the Kemmerer Drop. Upon closing the Kemmerer Drop, we own 100% of the outstanding equity interests in WKL, which owns and operates the Kemmerer mine in Lincoln County, Wyoming. The contribution of net assets of WKL was accounted for as a transaction between entities under common control whereby the WKL was recorded at historical book value. As such, the consideration paid in excess of the net assets contributed by WCC amounted to $13.2 million.
This transfer of net assets between entities under common control was accounted for as if the transfer occurred on December 31, 2014, the first point of common control. Accordingly, our consolidated financial statements include the historical results of both the Partnership and WKL for all periods presented while under common control (periods including and subsequent to December 31, 2014). We recognize transfers of net assets between entities under common control at WCC’s basis in the net assets contributed. The amount of the purchase price in excess or in deficit of WCC’s basis in the net assets is recognized as a reduction or an addition to limited partners’ equity. The financial statements of WKL have been prepared from the separate records maintained by WCC and may not necessarily be indicative of the conditions that would have existed or the results of operations if WKL had been operated as an unaffiliated entity during the periods reported.
4. RESTRUCTURING AND IMPAIRMENT CHARGES
WCC Transactions Restructuring
Concurrently with WCC’s acquisition of the GP in December 2014 (collectively, the "WCC Transactions"), we and WCC initiated a restructuring plan to streamline operations and eliminate duplicative roles and responsibilities between us and WCC. As of December 31, 2014, we recorded restructuring charges for employee termination benefits of $2.8 million and incurred additional restructuring costs of $0.7 million for the year ended December 31, 2015.
WCC Transactions restructuring accrual activity is summarized as follows (in thousands):
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The following table summarizes the total WCC Transactions restructuring charges incurred over the course of the restructuring (in thousands):
Impairment Charges
In April 2016, our Ohio operations entered into an agreement (the “Purchase Coal Agreement”) to purchase 1.0 million tons of coal (“Purchased Coal”) from a third party through December 31, 2017. The Purchased Coal will be used to fulfill specific customer sales orders under preexisting long-term sales agreements. As a result of the Purchased Coal Agreement, we down-sized our work force and incurred and paid $0.3 million severance charge and recognized an impairment charge on excess equipment of $8.1 million during the twelve months ended December 31, 2016. Additionally, during the twelve months ended December 31, 2016, our Kemmerer operations incurred an impairment charge of $3.2 million on a shovel which was parted out. We intend to market and sell excess parts within the next 12 months; thus, we reflected the expected amount to be recovered, based on prices for similar assets less our costs to sell, as “Assets held for sale” on the consolidated balance sheet.
5. INVENTORIES
Inventories consisted of the following:
6. RESTRICTED INVESTMENTS AND BOND COLLATERAL
For all of its restricted investments and bond collateral accounts, the Partnership can select from limited fixed-income investment options for the funds and receive the investment returns on these investments. Funds in the restricted investments and bond collateral accounts are not available to meet the Partnership’s general cash needs.
These accounts include available-for-sale securities in short-term bond collateral investments. Available-for-sale securities are reported at fair value with unrealized gains and losses excluded from earnings and reported in Accumulated other comprehensive loss.
The cost basis of an investment sold is specifically identified.
The carrying value and estimated fair value of its restricted investments and bond collateral at December 31, 2016 were as follows:
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The carrying value and estimated fair value of its restricted investments and bond collateral at December 31, 2015 were as follows:
In, 2016, and 2015, the Partnership recorded no realized gains or losses on the sale of available-for-sale securities held as restricted investments and bond collateral.
Available-for-Sale Restricted Investments and Bond Collateral
The cost basis, gross unrealized holding gains and losses and fair value of available-for-sale securities are as follows:
The aggregate related fair value of our 33 and 11 investments with unrealized losses as of December 31, 2016 and 2015, respectively, were as follows:
Maturities of available-for-sale securities were as follows at December 31, 2016:
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7. POSTRETIREMENT MEDICAL BENEFITS
Immediately prior to the Kemmerer Drop and in accordance with the Contribution Agreement, all employees of WKL were transferred to WCC. WCC assumed all liabilities associated with the Excluded Liabilities, including but not limited to postretirement medical benefits on August 1, 2015.
Prior to August 1, 2015, WKL provided postretirement medical benefits pursuant to collective bargaining agreements. These benefits were provided through self-insurance programs. As the Kemmerer Drop is accounted for as a transfer of net assets between entities under common control, our consolidated financial statements include the historical results of WKL, including postretirement medical expense, pension expense and income taxes, for the periods while under common control prior to the Kemmerer Drop (period of December 31, 2014 through August 1, 2015). In accordance with the Contribution Agreement, subsequent to the Kemmerer Drop, WCC, in compliance with the services agreement with our GP, as amended through the date hereof (the "Services Agreement"), and the Partnership Agreement, will allocate expenses incurred for postretirement medical liabilities attributable to the transferred employees on a cash basis through the period ending December 31, 2017. Thereafter, WCC shall allocate such expenses in its sole discretion, in compliance with the Services Agreement and the Partnership Agreement.
WKL provided 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. WKL also provided these benefits to qualified full-time employees pursuant to collective bargaining agreements. These benefits are provided through self-insured programs.
The following table sets forth the actuarial present value of postretirement medical benefit obligations and amounts recognized in the financial statements:
Actuarial gains and losses are amortized over the average future service of the plan’s participants. The Partnership will not have any amounts amortized from accumulated other comprehensive (loss) income into net periodic benefit cost in periods after July 31, 2015.
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The components of net periodic postretirement medical benefit cost are as follows:
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:
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8. PENSION AND OTHER SAVING PLANS
Immediately prior to the Kemmerer Drop and in accordance with the Contribution Agreement, all employees of WKL were transferred to WCC. WCC assumed all liabilities, including the pension assets, associated with the Excluded Liabilities, including but not limited to pension benefits on August 1, 2015.
Prior to August 1, 2015, WKL provided a defined benefit pension plan to qualified full-time employees pursuant to a collective bargaining agreement. Benefits are generally based on years of service and a specific dollar amount per year of service as specified in the plan agreement. As the Kemmerer Drop is accounted for as a transfer of net assets between entities under common control, our consolidated financial statements include the historical results of WKL, including postretirement medical expense, pension expense and income taxes, for the periods while under common control prior to the Kemmerer Drop (period of December 31, 2014 through August 1, 2015). In accordance with the Contribution Agreement, subsequent to the Kemmerer Drop, WCC, in compliance with the services agreement with our GP, as amended through the date hereof (the "Services Agreement"), and the Partnership Agreement, will allocate expenses incurred for pension liabilities attributable to the transferred employees on a cash basis through the period ending December 31, 2017. Thereafter, WCC shall allocate such expenses in its sole discretion, in compliance with the Services Agreement and the Partnership Agreement.
Defined Benefit Pension Plans
WKL provided a defined benefit pension plan to qualified full-time employees pursuant to a collective bargaining agreement. Benefits are generally based on years of service and a specific dollar amount per year of service as specified in the plan agreement. WKL’s funding policy is to contribute annually the minimum amount prescribed, as specified by applicable regulations.
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 WKL’s financial statements for the defined benefit pension plan:
The Partnership will not have any amounts amortized from accumulated other comprehensive (loss) income into net periodic benefit cost in periods after July 31, 2015.
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The components of net periodic benefit cost are as follows:
These costs are included in the accompanying statements of operations in Cost of coal revenues and 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:
WKL 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. WKL 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 WKL. The risk assessment provides a link 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.
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The Partnership does not support and has never had a pension plan throughout its existence.
Contributions
In 2015 prior to the Kemmerer Drop, WKL made $0.4 million of pension plan contributions. No pension plan contributions were made for 2016.
Other Plans
The GP sponsors 401(k) saving plans for employees of the GP to assist employees in providing for their future retirement needs. For the years ended December 31, 2016, 2015, and 2014, we did not commit to make and we did not and/or are not making any discretionary employer contribution to the 401(k) plan. Costs recognized during these same years were, $1.6 million, $0.4 million, and zero, respectively.
9. LEASES
We lease certain operating facilities and equipment under noncancelable lease agreements that expire on various dates through 2020. Generally, the lease terms range from three to ten years. The following shows the gross value and accumulated amortization of property, plant and equipment under capital leases related to the leasing of mining equipment as of December 31, 2016 and 2015:
Future minimum capital and operating lease payments as of December 31, 2016, are as follows:
Rental expense under operating leases during the years ended December 31, 2016, 2015 and 2014, totaled $7.3 million, $9.9 million and $8.8 million, respectively.
We have also entered into various coal reserve lease agreements under which advance royalty payments are made. Most of these advance royalty payments are recoupable against future royalty payments otherwise due based on production. Such payments are capitalized as Advanced coal royalties at the time of payment, and are recoupable through an offset or credit against royalties payable on future production.
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The Partnership 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 $12.8 million, $13.2 million and $11.2 million, for the years ended December 31, 2016, 2015 and 2014, respectively.
10. INTANGIBLE ASSETS
Identifiable intangible assets acquired in a business combination must be recognized and reported separately from goodwill. In December 2014, as part of the purchase accounting consideration discussed in Note 3. Acquisition And Pushdown Accounting to the consolidated financial statements, we have determined that the most significant acquired identifiable intangible asset is related to a beneficial lease agreement. Intangible assets result from more favorable contract prices than market prices in lease agreements as measured during a business combination. Our intangible asset is amortized on a straight-line basis over the remaining term of the lease agreement.
Expected amortization of intangible assets will be approximately (in thousands):
We evaluate our intangible assets for impairment when indicators of impairment exist. For the years ended December 31, 2016 and 2015, there were no indicators of impairment present for our intangible assets, and we believe the remaining useful lives to be appropriate.
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11. OTHER CURRENT ASSETS AND LIABILITIES
Other current assets consisted of the following:
Other current liabilities consisted of the following:
12. ASSET RETIREMENT OBLIGATIONS
As previously indicated, our asset retirement obligations arise from the Surface Mining Control and Reclamation Act of 1977, or SMCRA and similar state statutes, which require that mine property be restored in accordance with specified standards and an approved reclamation plan. The required reclamation activities to be performed are outlined in our mining permits. These activities include reclaiming the pit and support acreage, as well as stream mitigation.
As of December 31, 2016, our ARO totaled $52.2 million, including amounts reported as current liabilities. While the precise amount of these future costs cannot be determined with certainty, we estimate that, as of December 31, 2016, the aggregate undiscounted cost of final ARO is $79.4 million.
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Changes in the Partnership’s asset retirement obligations were as follows:
As permittee, the Partnership or its subsidiaries are responsible for the total amount of final reclamation costs for its mines. Costs of reclamation of mining pits prior to mine closure are recovered in the price of coal shipped.
As of December 31, 2016, the Partnership had $134.4 million in surety bonds outstanding to secure reclamation obligations. The surety bonds were secured by $37.7 million in restricted investments and bond collateral at December 31, 2016.
13. LONG-TERM DEBT
The amounts outstanding under the Partnership’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:
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The Partnership engages in leasing transactions for office equipment and equipment utilized in its mining operations. At December 31, 2016, the capital leases outstanding had a weighted average interest rate of 4.46%, and mature at various dates beginning in 2017 through 2020.
Term Loan
On December 31, 2014, we entered into a term loan ("Term Loan " or "2014 Financing Agreement") which consists of $175 million, with an option for an additional $120 million in term loans for acquisitions, which was exercised on August 1, 2015 to finance the Kemmerer Drop. Proceeds from the credit facility were used to retire our previously existing first and second lien credit facilities and to pay fees and expenses related to our existing credit facility, with the remaining proceeds being available as working capital. The Term Loan matures on December 31, 2018, was not issued at a discount or a premium and $8.6 million of debt issuance costs were recognized at December 31, 2014. The Term Loan bears interest at a variable rate per annum equal to, at our option, the London Interbank Offered Rate ("LIBOR") (floor of 0.75% plus 8.5%) or the reference rate as defined in the financing agreement. As of December 31, 2016, the Term Loan had a cash interest rate of 9.45%. The Term Loan is a primary obligation of Oxford Mining Company, LLC, a wholly owned subsidiary of the Partnership, is guaranteed by the Partnership and its subsidiaries, and is secured by substantially all of our and our subsidiaries’ assets. At December 31, 2016, we were in compliance with all covenants of the Term Loan.
The Term Loan also provides for Paid-In-Kind interest (“PIK Interest”) at a variable rate per annum between 1.00% and 3.00% based on our consolidated total net leverage ratio as defined in the financing agreement. The rate of PIK Interest is recalculated on a quarterly basis with the PIK Interest added quarterly to the then-outstanding principal amount of the Term Loan. PIK Interest under the Term Loan was $9.2 million for the twelve months ended December 31, 2016. The outstanding Term Loan amount represents the principal balance of $290.1 million, plus PIK Interest of $16.1 million.
As a result of refinancing the 2014 Financing Agreement, we recorded a $1.6 million loss on extinguishment of debt in the year ended December 31, 2014 as it pertains to cost associated with repayment of the previously existing first and second lien credit facilities.
In connection with the Kemmerer Drop, the Term Loan was amended on July 31, 2015 to (i) allow us 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 we have a revolving loan facility available, require us 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. As of December 31, 2016, we have made $14.2 million in Restricted Distributions. If we are unable to refinance or modify our Term Loan, our ability to comply with covenants and restriction contained in the Term Loan that allows for the issuance of a cash distribution is at risk for periods beyond September 30, 2017.
Deferred Financing Costs
We capitalized $7.0 million of deferred financing costs related to the 2014 Financing Agreement during the year ended December 31, 2014. These costs, included in Deferred financing costs, net, represent fees paid to lenders and advisors and for legal services.
Amortization of deferred financing costs included in interest expense was $2.7 million, $2.3 million and $4.1 million for the years ended December 31, 2016, 2015 and 2014, respectively.
Revolver
On October 23, 2015, the Partnership and its subsidiaries entered into a Loan and Security Agreement (the “Revolver”) with the lenders party thereto and The PrivateBank and Trust Company. Our Revolver permits us to borrow up to the aggregate principal amount of $15.0 million and also allows letters of credit in an aggregate outstanding amount of up to $10.0 million, which reduces availability under the Revolver on a dollar-for-dollar basis. At December 31, 2016, availability under the Revolver was $15.0 million. The Revolver has a maturity date of December 31, 2017.
We may elect interest under the Revolver to accrue at either (i) the Base Rate, which bears interest at the greater of (A) the Federal Funds Rate plus 0.50% or (B) the Prime Rate, in each case, plus 0.75% (payable monthly), or (ii) the LIBOR Rate, which bears interest for the relevant period as offered in the London Interbank Eurodollar market plus 2.75% (payable on the last
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day of the applicable interest period). In addition, an unused line fee of 0.50% of the average unused portion of the Loan Facility is payable monthly.
The Revolver includes a quarterly fixed charge coverage ratio covenant as well as incurrence-based financial covenants regarding the Partnership’s fixed charges and total net leverage and otherwise contains customary affirmative covenants, negative covenants and events of default. All extensions of credit under the Revolver are collateralized by a first priority security interest in and lien upon the inventory, accounts receivable and cash of the Partnership. We were in compliance with all covenant requirements as of December 31, 2016.
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. We are 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, 2016 (Level 3).
The estimated fair value of the Partnership’s debt with fixed and variable interest rates are as follows:
The table below sets forth, by level, the Partnership’s financial assets and liabilities that are accounted for at fair value on a recurring basis:
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15. DISTRIBUTIONS OF AVAILABLE CASH
We distribute 100% of our available cash within 45 days after the end of each quarter to unitholders of record and to our general partners. Available cash is generally defined in the partnership agreement as all cash and cash equivalents on hand at the end of each quarter less reserves established by our managing general partner in its reasonable discretion for future cash requirements. These reserves are retained to provide for the conduct of our business, the payment of debt principal and interest and to provide funds for future distributions.
As quarterly distributions of available cash exceed the target distribution levels established in our partnership agreement, our managing general partner receives distributions based on specified increasing percentages of the available cash that exceeds the target distribution levels. The target distribution levels are based on the amounts of available cash from our operating surplus distributed for a given quarter that exceed the minimum quarterly distribution (“MQD”). Our partnership agreement defines the MQD as $0.1333 per unit ($0.5332 per unit on an annual basis). On December 31, 2014 as part of the restructuring of the Partnership the IDR were suspended for six quarters, provided that such suspension may be reduced to three quarters if, during the suspension period, additional dropdown transactions aggregating greater than $35.0 million in enterprise value are undertaken by our GP or affiliates of our GP that are reasonably expected to provide accretion to per unit common unitholder distributions.
Under the quarterly IDR provisions of our partnership agreement, our managing general partner is entitled to receive (i) 13% of quarterly distributions over $0.1533 per unit and up to $0.1667 per unit; (ii) 23% of quarterly distributions over $0.1667 per unit and up to $0.2000 per unit; and (iii) 48% of quarterly distributions over $0.2000 per unit. For the years ended December 31, 2016, 2015 and 2014, we did not allocate to our managing general partner any incentive distributions. The following table summarizes the quarterly per unit distribution paid during the respective quarter:
We made cash distributions as follows:
On January 27, 2017, we declared a quarterly cash distribution for the quarter ended December 31, 2016, of $0.1333 per common unit and warrant with distribution rights. Additionally, we declared a paid-in-kind unit distribution of $0.1333 per Series A Convertible Unit. The cash distribution totaling approximately $0.2 million, was paid to all common unitholders and warrant holders on February 14, 2017 to all unitholders of record as of February 7, 2017. As of February 14, 2017, we have made $14.4 million in Restricted Distributions under our Term Loan.
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16. LONG-TERM INCENTIVE PLAN
Under our LTIP, we recognize equity-based compensation expense over the vesting period of the units. These units are subject to conditions and restrictions as determined by our Compensation Committee, including continued employment or service. For the years ended December 31, 2016, 2015 and 2014, we recognized equity-based compensation expense of $252 thousand, $439 thousand and $4.6 million. These amounts are included in Cost of coal revenues and Selling and administrative expenses. The value of LTIP units vested during the years ended December 31, 2016 and 2014 was $86 thousand and $5.6 million, respectively. No LTIP units vested during the year ended December 31, 2015. The following table summarizes additional information concerning our unvested LTIP units:
17. PARTNERS' CAPITAL AND CONVERTIBLE UNITS
Our capital accounts are comprised of approximately 0.16% beneficial general partner interests and 99.84% limited partner interests as of December 31, 2016. Our limited partners have limited rights of ownership as provided for under our Partnership Agreement and the right to participate in our distributions. Our General Partner manages our operations and participates in our distributions, including certain incentive distributions pursuant to the incentive distribution rights that are nonvoting limited partner interests held by our General Partner. Pursuant to our Partnership Agreement, our General Partner participates in losses and distributions based on its interest. The General Partner's participation in the allocation of losses and distributions is not limited and therefore, such participation can result in a deficit to its capital account. As such, allocation of losses and distributions, including distributions for previous transactions between entities under common control, has resulted in a deficit to the Limited Partners’ capital account included in our condensed consolidated balance sheets.
Series A Units
WCC, the owner of our General Partner, holds and participates in distributions on our Series A Units. Series A Units have the right to share in distributions from us on a pro-rata basis with the common units. All or any portion of each distribution payable in respect of the Series A Units (the “Series A Convertible Unit Distribution”) may, at our Board of Directors' election, be paid in Series A paid-in-kind Units (“Series A PIK Units”). To the extent any portion of the Series A Convertible Unit Distribution is paid in Series A PIK Units for any quarter, the distribution to the holders of incentive distribution rights shall be reduced by that portion of the distribution that is attributable to the payment of those Series A PIK Units. The Series A Units will convert into common units, on a one-for-one basis, at the earlier of the date on which we first make a regular quarterly cash distribution with respect to any quarter to holders of common units in an amount at least equal to $0.22 per common unit or upon a change of control. The Series A Units have the same voting rights as if they were outstanding common units and will vote together with the common units as a single class. In addition, the Series A Units are entitled to vote as a separate class on any matters that materially adversely affect the rights or preferences of the Series A Units in relation to other classes of partnership interests or as required by law.
Series B Convertible Units
On October 28, 2016, we issued 4,512,500 Series B Convertible Units representing limited partner interests in the Partnership (the “Series B Units”) to WCC in exchange for WCC’s 4,512,500 common units (the “Exchange”). Upon issuance of the Series B Units in the Exchange, WCC’s common units were canceled. The Series B Units do not share in distributions with
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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
the common units and are convertible at the option of the holder on a one-for-one basis into common units on the day after the record date for a cash distribution on the common units in which the Partnership is unable to make such a distribution without exceeding its restricted payment basket under the 2014 Financing Agreement (as defined in Note 13. Long-Term Debt to the consolidated financial statements). The Series B Units will convert automatically upon a change of control or a dissolution or liquidation of the Partnership. The Series B Units have the same voting rights as if they were outstanding common units and will vote together with the common units as a single class. In addition, the Series B Units are entitled to vote as a separate class on any matters that materially adversely affect the rights or preferences of the Series B Units in relation to other classes of partnership interests or as required by law. Concurrently with the Exchange, we entered into Amendment No. 2 to the Partnership Agreement, which established aforementioned terms of the Series B Units.
Liquidation Units
All subordinated units were transferred to WCC in connection our General Partner being acquired on December 31, 2014. These units were then converted to liquidation units which have no distribution or voting rights, other than in connection with liquidation. For tax purposes, liquidation units are allocated additional taxable income but no additional taxable loss compared to other unit classes.
Warrants
In June 2013, in connection with a prior credit facility, certain lenders and lender affiliates received warrants entitling them to purchase 166,557 common units at $0.12 per unit. The warrants participate in distributions whether or not exercised.
Outstanding Units
Net Income (Loss) attributable to Limited Partners
Net income (loss) is allocated to the General Partner and the limited partners in accordance with their respective ownership percentages, after giving effect to distributions and declared distribution on Series A Convertible Units, and General Partner units, including incentive distribution rights. Unvested unit-based payment awards that contain non-forfeitable rights to distributions (whether paid or unpaid) are classified as participating securities and are included in our computation of basic and diluted limited partners' net income (loss) per common unit. Basic and diluted limited partners' net income (loss) per common unit is calculated by dividing limited partners' interest in net income (loss) by the weighted average number of outstanding limited partner units during the period. We determined basic and diluted limited partners' net income (loss) per common unit as follows (in thousands, except per unit amounts):
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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
1Unvested LTIP units are not dilutive units for the periods presented herein, but could be in the future. Anti-dilutive units are not used in calculating diluted average units.
2Reflects the impact of the outstanding common unit warrants for the three and nine months ended December 31, 2016 and 2015, respectively.
The impact of the Kemmerer Drop on income (loss) per limited partner units for the twelve months ended December 31, 2015 is as follows:
18. NONCONTROLLING INTEREST
Harrison Resources, a limited liability company, was formed in March 2006 by Oxford Mining to acquire coal properties, develop mine sites and mine coal for sale to customers. Effective January 30, 2007, 49% of Harrison Resources was sold to an affiliate of Consol Energy, Consol of Ohio LLC ("Consol").
Effective October 1, 2014, Oxford Mining entered into and closed under a membership interest redemption agreement with Harrison Resources and Consol under which Harrison Resources redeemed all of Consol’s interest in Harrison Resources. As a result of the redemption, Oxford Mining owns 100% of Harrison Resources. In connection with the redemption, Harrison Resources acquired 0.9 million tons of coal reserves from a Consol affiliate, and also options to purchase an aggregate of 5.6 million additional tons of coal reserves from a Consol affiliate. These tons are in addition to the 1.7 million tons of coal reserves already owned by Harrison Resources. Harrison Resources paid total consideration of $3.6 million in these transactions.
Harrison Resources’ revenues, which are included in our consolidated statements of operations, were $23,341 for the Predecessor period January 1, 2014 through December 31, 2014. Oxford Mining had a services agreement with Harrison Resources under which we performed mining and reclamation services for agreed-upon per ton prices. Additionally, Oxford Mining had a broker agreement with Harrison Resources under which we marketed the coal.
Noncontrolling interest, which represents the 49% of Harrison Resources owned by Consol through Oct 1, 2014, consisted of the following:
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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
19. WORKERS’ COMPENSATION AND BLACK LUNG
As of December 31, 2016, we have a $1.8 million liability under state statutes and the Federal Coal Mine Health and Safety Act of 1969, as amended, to pay black lung benefits to eligible employees, former employees and their dependents, recorded on the balance sheet in Other liabilities. Under the Black Lung Benefits Revenue Act of 1977, as amended in 1981, each coal mine operator must pay federal black lung benefits to claimants who are current and former employees and also make payments to a trust fund for the payment of benefits and medical expenses to claimants who last worked in the coal industry prior to January 1, 1970. The trust fund is funded by an excise tax on production of up to $1.10 per ton for deep-mined coal and up to $0.55 per ton for surface-mined coal, with neither amount to exceed 4.4% of the gross sales price for the coal. For the years ended December 31, 2016, 2015 and 2014, we recorded $3.8 million, $4.6 million and $2.9 million, respectively, in our cost of coal revenues related to this excise tax.
With regard to workers’ compensation, we are insured through state sponsored programs or an insurance carrier where there is no state sponsored program.
20. INCOME TAX
We are not a taxable entity for federal or state income tax purposes; the tax effect of our activities pass-through to the unitholders. Although publicly traded partnerships as a general rule will be taxed as corporations, we qualify for an exception because at least 90% of our income consists of qualifying income, as defined in Section 7704(c) of the Internal Revenue Code. Net income for financial statement purposes may differ significantly from taxable income reportable to unitholders as a result of differences between the tax basis and financial reporting basis of assets and liabilities, differing depreciation or amortization rates, and the taxable income allocation requirements under our partnership agreement. Individual unitholders have different investment bases depending upon the timing and price of acquisition of their partnership units. Furthermore, each unitholder’s tax accounting, which is partially dependent upon the unitholder’s tax position, differs from the accounting followed in our consolidated financial statements. Accordingly, the aggregate difference in the basis of our net assets for financial and tax reporting purposes cannot be readily determined because information regarding each unitholder’s tax attributes in our partnership generally is not available to us.
Prior to the Kemmerer Drop, WKL was subject to income taxes in the United States (including federal and state income taxes). Deferred income taxes were 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, WKL considered 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.
As of December 31, 2016, WKL has not recorded a reserve for uncertain tax positions or penalties and interest. WKL does not anticipate a significant change that would require a reserve to be established for uncertain tax positions in the next 12 months. WKL filed federal and state income tax returns that are subject to examination by the Internal Revenue Service and certain state tax authorities. The tax years open to examination include 2013 through July 31, 2015.
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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
21. COMMITMENTS AND CONTINGENCIES
Coal Sales Contracts
We are committed under long-term contracts to sell coal that meets certain quality requirements at specified prices. Many of these prices are subject to cost pass-through or cost adjustment provisions that mitigate some risk from rising costs. Quantities sold under some of these contracts may vary from year to year within certain limits at the option of the customer or us. As of December 31, 2016, the remaining terms of our long-term contracts range from one to ten years.
Purchase Commitments
From time to time, we purchase coal from third parties in order to meet quality or delivery requirements under our customer contracts. We buy coal on the spot market, and the cost of that coal is dependent upon the market price and quality of the coal.
Surety and Performance Bonds
As of December 31, 2016, we had $134.4 million in surety bonds outstanding to secure certain reclamation obligations which were collateralized by cash deposits and restricted investments of $37.7 million. Such cash collateral is included in Restricted investments and bond collateral on our consolidated balance sheets and Change in restricted investments and bond collateral within investing activities on our consolidated statements of cash flow. Additionally, we had road bonds totaling $0.4 million and performance bonds totaling $2.9 million outstanding to secure contractual performance. We believe these bonds will expire without any claims or payments thereon and therefore will not have a material adverse effect on our financial position, liquidity or operations.
Legal and Regulatory
Ohio Environmental Protection Agency Challenge
In May of 2016 the Ohio EPA (“OEPA”) notified Oxford Mining Company, LLC (“Oxford”), in writing that OEPA believed various of the Oxford’s previously remediated mines have failed to meet the performance goals set forth in the approved mitigation plans. OEPA’s letters allow that Oxford either a) provide evidence that OEPA’s listed mitigation deficiencies are actually meeting the performance standards, b) request an extension of up to two years to complete the outstanding mitigation obligations, or c) pursue off-site mitigation credit such as purchasing mitigation credits from third parties. None of the written correspondence specified monetary damages or cost estimates to complete. Presently, our position is that the exposure is inconsequential based on our studies.
Other Legal Proceedings
In July 2014, we concluded litigation, with a former customer who wrongfully terminated its coal supply agreement with us, by entering into a settlement agreement under which the former customer paid us $19.5 million to compensate us for lost profits on coal sales to it due to the termination. We believe this settlement amount substantially compensates us for the damages we incurred due to the wrongful termination.
We are involved in other legal proceedings arising in the ordinary course of business and may become involved in additional proceedings from time to time. We accrue for liabilities when it is probable that future costs (including legal fees and expenses) will be incurred and such costs can be reasonably estimated. Accruals are based on developments to date; management's estimates of the outcomes of these matters; our experience in contesting, litigating and settling similar matters; and any related insurance coverage. While the ultimate outcome of these proceedings cannot be predicted with certainty, we have accrued $0.3 million to resolve various claims as of December 31, 2016, of which $0.3 million, net, was accrued during 2016.
We believe that there are no other legal proceedings pending that are likely to have a material adverse effect on our consolidated financial condition, results of operations or cash flows. Nevertheless, we cannot predict the impact of future developments affecting our claims and lawsuits, and any resolution of a claim or lawsuit or an accrual within a particular fiscal period may materially and adversely impact our results of operations for that period. In addition to claims and lawsuits against us, our operations, permits, and other industry regulatory processes and approvals, including those applicable to the utilities and transportation industries, may also continue to be subject to legal challenges that could materially and adversely impact our mining operations, results and liquidity. These regulatory challenges may seek to vacate prior regulatory decisions and
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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
authorizations that are legally required for some or all of our current or planned mining activities. If we are required to reduce or modify our mining activities as a result of these challenges, the impact could have a material adverse effect on our shipments, financial results and liquidity, and could result in claims from third parties if we are unable to meet our commitments under pre-existing commercial agreements as a result of any such required reductions or modifications to our mining activities.
Guarantees
Our GP and the Partnership guarantee certain obligations of our subsidiaries. We believe that these guarantees will expire without any liability to the guarantors, and therefore will not have a material adverse effect on our financial position, liquidity or operations.
22. CONCENTRATION OF CREDIT RISK AND MAJOR CUSTOMERS
We have a credit policy that establishes procedures to determine creditworthiness and credit limits for customers. Generally, credit is extended based on an evaluation of the customer’s financial condition. Collateral is not generally required, unless credit cannot be established.
In 2016 and 2015, we marketed our coal principally to electric utilities, electric cooperatives, municipalities and industrial customers in Indiana, Wyoming, Kentucky, Michigan, Ohio, Pennsylvania and West Virginia. As of December 31, 2016 and 2015, accounts receivable from electric utilities totaled $27.8 million and $24.4 million, respectively, or 73.9% and 74.8% of total receivables, respectively. The following table shows the amount of sales to each customer (in each year where applicable, a “Major Customer”) which individually accounted for 10% or more of sales in any of the years ended December 31, 2016, 2015 and 2014, with a portion of these sales being facilitated by coal brokers.
The Major Customers in 2016, 2015 and 2014, in the aggregate, represented 77.3%, 75.4% and 80.2%, respectively, of our total sales in the applicable year. The Major Customers in each of 2016 and 2015, in the aggregate, represented 73.9% and 74.8% of the outstanding accounts receivable at December 31, 2016 and 2015, respectively.
23. ACCUMULATED OTHER COMPREHENSIVE (LOSS) INCOME
The following table reflects the changes in accumulated other comprehensive (loss) income by component:
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The following table reflects the reclassifications out of accumulated other comprehensive (loss) income for the years ended December 31, 2016 and 2015:
24. RELATED PARTY TRANSACTIONS
The Board of Directors of our managing general partner (“Board of Directors”) and its conflicts committee (“Conflicts Committee”) review our related party transactions that involve a potential conflict of interest between a general partner and WMLP or its subsidiaries or another partner to determine that such transactions reflect market-clearing terms and conditions customary in the coal industry. As a result of these reviews, the Board of Directors and the Conflicts Committee approved each of the transactions described below that had such potential conflict of interest as fair and reasonable to us and our limited partners.
In connection with our formation in August 2007, the Partnership and Oxford Mining entered into an administrative and operational services agreement (the “Services Agreement”) with our GP. The Services Agreement is terminable by either party upon thirty days’ written notice. Under the terms of the Services Agreement, our GP provides services through its employees to us and is reimbursed for all related costs incurred on our behalf. Pursuant to the Services Agreement, the Partnership engaged the GP to continue providing services such as general administrative and management, engineering, operations (including mining operations), geological, corporate development, real property, marketing, and other services to the Partnership. Administrative services include without limitation legal, finance and accounting, treasury, insurance administration and claims processing, risk management, health, safety and environmental, information technology, human resources, credit, payroll, internal audit and tax. Under the Service Agreement, the Partnership pays the GP a fixed management fee of $2.2 million for certain executive and administrative services, and reimburses the GP at cost for other expenses and expenditures. The term of the Services Agreement expires on December 31, 2017, and automatically renews for successive one year periods unless terminated. Pursuant to the Services Agreement, the primary reimbursements to our GP were for costs related to payroll. Reimbursable costs under the Services Agreement totaling $2.7 million and $4.2 million were included in accounts payable as of December 31, 2016 and 2015, respectively. In December 2016 and 2015, the Partnership prepaid the GP for the 2017 and 2016 annual management fee of $2.2 million, which was included in Other current assets at December 31, 2016 and 2015, respectively.
We sell clay, small quantities of coal, and perform non-coal services to Tunnell Hill Reclamation, LLC (“Tunnell Hill”), a company that is indirectly owned by a member of our Board of Directors. Sales to Tunnell Hill were $0.6 million and $1.2 million for the years ended December 31, 2015 and 2014, respectively. Accounts receivable from Tunnell Hill were $0.2 million for the years ended December 31, 2015.
Finally, we sold coal to and performed various transportation and operational services for a subsidiary of WCC, which generated $25.2 million and $30.9 million in coal revenues and $0.04 million and $2.4 million in non-coal revenues for the years ended December 31, 2016 and 2015, respectively. As of December 31, 2016 and 2015, accounts receivables related to the aforementioned revenue totaled $6.7 million and $3.4 million and were included in Receivables - trade.
On January 9, 2017 the Partnership acquired surface coal reserves through conveyance of leases and recoupable advance royalty payments from Buckingham Coal Company, LLC ("BCC"), a wholly owned subsidiary of WCC, for $1.8 million.
25. SEGMENT INFORMATION
We operate in one business segment. We operate surface coal mines in Northern Appalachia, Lincoln County, Wyoming and in the Illinois Basin through December 2013, selling high-value thermal coal to utilities, industrial customers, municipalities and other coal-related entities primarily in the Midwest and northeastern U.S. All of our operations have similar economic characteristics including but not limited to coal quality, geology, coal marketing opportunities, mining and transportation methods and regulatory issues. Our operating and executive management makes its decisions based on consolidated reports. Three of our seven operating subsidiaries extract coal utilizing surface-mining techniques and prepare it for sale to their customers. Such operating subsidiaries share customers and a particular customer may receive coal from any one of such operating subsidiaries. We also lease or sublease coal reserves to others through Oxford Mining in exchange for a per ton royalty rate.
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26. SUPPLEMENTAL QUARTERLY FINANCIAL INFORMATION - (Unaudited)
A summary of our unaudited consolidated quarterly operating results in 2016 and 2015 is as follows:
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27. SUBSEQUENT EVENTS
The Partnership has evaluated subsequent events in accordance with ASC 855, Subsequent Events, through the filing of its Annual Report, and determined that there have been no events that have occurred that would require adjustments to disclosures in the consolidated financial statements.
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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 RESOURCE PARTNERS, LP
By:
WESTMORELAND RESOURCES GP, LLC, its general partner
March 16, 2017
By:
/s/ Kevin A. Paprzycki
Kevin A. Paprzycki
Chief Executive Officer
(Principal Executive Officer)
Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below by the following persons in their indicated capacities, which are with the general partner of the registrant, on the dates indicated.
WESTMORELAND RESOURCE PARTNERS, LP AND SUBSIDIARIES
Index to Exhibits
WESTMORELAND RESOURCE PARTNERS, LP AND SUBSIDIARIES
WESTMORELAND RESOURCE PARTNERS, LP AND SUBSIDIARIES
WESTMORELAND RESOURCE PARTNERS, LP AND SUBSIDIARIES