Indicate by check mark if the registrant is a well-known seasoned issuer, as defined in Rule 405 of the Securities Act. Yes ¨ No x

Indicate by check mark if the registrant is not required to file reports pursuant to Section 13 or Section 15(d) of the Act. Yes ¨ No x

Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days. Yes x No ¨

Indicate by check mark whether the registrant has submitted electronically and posted on its corporate Web site, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T (§ 232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files). Yes x No ¨

Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, or a smaller reporting company. See the definitions of “large accelerated filer,” “accelerated filer” and “smaller reporting company” in Rule 12b-2 of the Exchange Act.

Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act). Yes ¨ No x

The aggregate market value of units held by non-affiliates of the registrant (which is exclusive also of units beneficially held by officers and directors of the registrant) as of June 30, 2014 was $353,991,400.

As of February 27, 2015, the registrant had 65,059,477 common units and 64,954,691 subordinated units outstanding.

Certain statements and information in this Annual Report on Form 10-K may constitute “forward-looking statements.” The words “believe,” “expect,” “anticipate,” “plan,” “intend,” “foresee,” “outlook,” “estimate,” “potential,” “continues,” “may,” “will,” “seek,” “approximately,” “predict,” “anticipate,” “should,” “would,” “could” or other similar expressions are intended to identify forward-looking statements, which are generally not historical in nature. These forward-looking statements are based on our current expectations and beliefs concerning future developments and their potential effect on us. While management believes that these forward-looking statements are reasonable as and when made, there can be no assurance that future developments affecting us will be those that we anticipate. All comments concerning our expectations for future revenues and operating results are based on our forecasts for our existing operations and do not include the potential impact of any future acquisitions. Our forward-looking statements involve significant risks and uncertainties (some of which are beyond our control) and assumptions that could cause actual results to differ materially from our historical experience and our present expectations or projections. Known material factors that could cause our actual results to differ from those in the forward-looking statements are described in Part I, Item 1A. “Risk Factors.”

Readers are cautioned not to place undue reliance on forward-looking statements, which are made only as of the date hereof. We undertake no obligation to publicly update or revise any forward-looking statements after the date they are made, whether as a result of new information, future events or otherwise.

All references to “FELP,” the “Partnership,” “we,” “us,” and “our” refer to the combined results of Foresight Energy LP and Foresight Energy LLC and its subsidiaries, unless the context otherwise requires or where otherwise indicated.

We mine and market coal from reserves and operations located exclusively in the Illinois Basin. Since our inception, we have invested over $2.0 billion to construct a fleet of state-of-the-art, low-cost and highly productive longwall mining operations and related transportation infrastructure. We control over 3 billion tons of coal in the state of Illinois, which, in addition to making us one of the largest reserve holders in the United States, provides significant organic growth opportunities. Our reserves consist principally of three large contiguous blocks of uniform, thick, high heat content (high Btu) thermal coal, which are ideal for highly productive longwall operations. Thermal coal is used by power plants and industrial steam boilers to produce electricity or process steam.

We own four mining complexes where we operate four longwall mines and one continuous miner operation. We have made preliminary capital expenditures to pursue permits for our fifth and sixth longwalls. Our four mining complexes can collectively support up to nine longwalls, with a portion of the existing surface infrastructure available to be shared among most of our future longwalls.

Our operations are strategically located near multiple rail and river transportation access points giving us cost-competitive transportation options. We have developed infrastructure that provides each of our four mining complexes with multiple transportation outlets including direct and indirect access to five Class I railroads. Our access to competing rail carriers as well as access to truck and barge transport provides us with operating flexibility and minimizes transportation costs. We have access to a 25 million ton per year barge-loading river terminal on the Ohio River, which was contributed to us in February 2015 by Foresight Reserves and a member of management, and contractual agreements for a minimum of 9 million tons per year of export terminal capacity in the Gulf of Mexico, including a terminal owned by an affiliate. We also have long-term, fixed price transportation contracts from our mines to both of these terminals. These logistical arrangements provide transportation cost certainty and the flexibility to direct shipments to markets that provide the highest margin for our coal sales.

We sell a significant portion of our coal under agreements with terms of one year or longer. We market and sell our coal to a diverse customer base, including electric utility and industrial companies in the eastern United States and the international market. In 2014, we sold 89.6% of our domestic tons to electric utilities, of which 93.9% was sold to utility plants with installed pollution control devices. These devices, also known as scrubbers, are designed to eliminate substantially all emissions of sulfur dioxide.

Foresight Energy LP, a Delaware limited partnership, completed its initial public offering on June 23, 2014 and is listed on the New York Stock Exchange (“NYSE”) under the ticker symbol “FELP.” We are managed and operated by the board of directors and executive officers of our general partner, Foresight Energy GP LLC, which is owned by Foresight Reserves L.P. (“Foresight Reserves”) and a member of management.

Below is a diagram of our organizational and ownership structure as of February 27, 2015:

Each of our four mining complexes operates in the Illinois Basin; two are located in Southern Illinois and two are located in Central Illinois. Williamson, Sugar Camp and Hillsboro are longwall operations, and Macoupin is currently a continuous miner operation. The geology, mine plan, equipment and infrastructure at each of our Williamson, Sugar Camp and Hillsboro mines are relatively similar and we anticipate similar productive capacity and productivity levels as we add additional longwalls. Each of our mining complexes has its own preparation plant and support facilities. The following map shows the location of our mining complexes and transportation network:

(1)“CN”: Canadian National line; “EVWR”: the Evansville Western line; “NS”: the Norfolk Southern line; “UP”: Union Pacific line; “BNSF”: BNSF Railway line; and “CSX”: CSX Corporation line.

The table below summarizes our operations, mining methods, transportation, reserves and production:

Longwall mining is a highly-automated, underground mining technique that generates high volumes of low-cost coal production and is typically supported by one or two continuous mining units. While the continuous mining units contribute to coal production, the primary function is to prepare an area of the mine for longwall operations. A longwall mining system uses a shearer to cut the coal, self-advancing roof supports to protect the miners working at the longwall face and an armored face conveyor to transport the coal. The longwall mining system is highly productive due to the continuous nature of the coal production and the high volume of coal produced relative to the number of personnel required to operate the system.

We have been able to sustain our highly productive and low operating costs since we started our first longwall in 2008, and the high productivity at the new mines we have developed demonstrates the repeatability of our mine design. The high productivity translates into low costs, and in 2014, our operations had an average cash cost of $20.80 per ton sold. We operated the three most productive underground coal mines in the United States during 2014 on a clean tons produced per man hour basis based on Mine Safety and Health Administration (“MSHA”) data, as illustrated below.

Source: MSHA data. Note: The chart above displays the top 25 most productive underground mines out of 234 mines with over 100,000 tons produced during 2014 on a clean tons produced per man hour basis. Darker shading denotes mines owned by Foresight Energy LP.

All of our mining operations utilize affiliated non-union contract mining companies who operate under contractual mining agreements (See “Employees and Labor Relations”). As of December 31, 2014, our affiliated contract mining companies, which we consolidate as variable interest entities, employed 888 contractors involved in mining and mining-related operations and we had 65 corporate employees.

Our Williamson mine is wholly-owned by our subsidiary Williamson Energy, LLC (“Williamson”) and is located in southern Illinois near the town of Marion. Williamson is the first mine we developed, with longwall mining production commencing in 2008. The mine operates in the Herrin No. 6 Seam, using one longwall system and two continuous miner units to develop the mains and gate roads for its longwall panels. Coal is washed at Williamson’s 2,000 tons-per-hour (“tph”) preparation plant, stockpiled and then shipped by rail or truck to market. Williamson’s coal is shipped via the CN railroad to the Ohio and Mississippi Rivers to serve the domestic thermal market or to New Orleans to serve the international market. Williamson has access to several barge facilities on the Ohio and Mississippi Rivers and two vessel loading facilities in New Orleans. Williamson was the second most productive underground coal mine in the United States in 2014 on a clean tons produced per man hour basis based on MSHA data.

Our Sugar Camp mine is wholly-owned by our subsidiary Sugar Camp Energy, LLC (“Sugar Camp”), and is located in southern Illinois approximately 12 miles north of Williamson. Sugar Camp’s first longwall system began production in the first quarter of 2012 and the second longwall system began production in the second quarter of 2014. Sugar Camp’s original infrastructure, including its bottom development, slope belt, material handling system and rail loadout, supports both longwalls. Sugar Camp operates in the Herrin No. 6 Seam and uses a similar mine design and similar equipment as Williamson. With additional equipment, infrastructure and mine development, Sugar Camp has the capacity to add two incremental longwall systems. Coal is washed at Sugar Camp’s two 2,000 tph preparation plants, stockpiled and then shipped by rail to market. Sugar Camp has direct access to the CN railroad which can deliver its coal to the Ohio and Mississippi Rivers to serve the domestic thermal market or to New Orleans to serve the international

market. Sugar Camp also has indirect access to the NS, BNSF and CSX railroads. Sugar Camp was the third most productive underground coal mine in the United States in 2014 on a clean tons produced per man hour basis based on MSHA data.

Our Hillsboro mine is wholly-owned by our subsidiary Hillsboro Energy LLC (“Hillsboro”), and is located in central Illinois near the town of Hillsboro. Hillsboro’s longwall mining system began production in the third quarter of 2012. The mine operates in the Herrin No. 6 Seam and uses similar mine design and similar equipment as Williamson and Sugar Camp. Coal is washed at Hillsboro’s 2,000 tph preparation plant, stockpiled and then shipped by rail or truck to market. Hillsboro has direct access to the UP and NS railroads and indirect access to the CN railroad, which allows for the delivery of its coal directly to customers or to the Ohio and Mississippi Rivers to serve the domestic thermal market or the international market through New Orleans. Hillsboro was the most productive underground coal mine in the United States in 2014 on a clean tons produced per man hour basis based on MSHA data.

Our Macoupin mine is wholly-owned by our subsidiary Macoupin Energy LLC (“Macoupin”), and is located in central Illinois near the town of Carlinville. We acquired the Macoupin mine from ExxonMobil Coal USA, Inc. (“Exxon”) in 2009. Following the acquisition from Exxon, Macoupin sealed the majority of the previously mined area and implemented a new mine plan and design. In addition, the surface facilities were upgraded, including the rehabilitation of the preparation plant. Coal production began in 2009 with a single continuous miner super-section utilizing battery powered coal haulers. An additional continuous miner unit was added in 2011 using a flexible conveyor train system rather than coal haulers. Coal is washed at Macoupin’s 850 tph preparation plant, stockpiled and then shipped by rail or truck to market. Macoupin has direct access to both the UP and NS railroads and indirect access to the CN railroad, which allows for the delivery of its coal directly to customers or to the Ohio and Mississippi Rivers to serve the domestic thermal market or the international market through New Orleans.

Our coal is transported to our domestic customers and export terminal facilities by rail, barge and truck. Depending on the proximity of our customers to the mines and the transportation available to deliver coal to that customer, transportation costs can be a substantial part of the total delivered cost of coal. Because our reserves and mines are favorably located near multiple rail and river transportation options, we believe we can negotiate advantageous transportation rates, allowing us to keep our transportation costs relatively low and provide broad market access for our coal.

We have direct and indirect rail access to domestic customers via five Class I railroads, river access to domestic customers via various Ohio and Mississippi River terminals, and river and rail access to coal export terminals for shipping to international customers. We have agreements with rail carriers that vary in initial length from one to twenty years. We also have favorable access to the international market through the CN railroad and an export terminal owned by an affiliate, discussed below. The international market provides us with an alternative to the domestic market and has been an important economic outlet for our coal. While transportation costs are higher for exports, we generally receive higher coal sale prices on export sales which offset the higher transportation costs. Rates and practices of the transportation company serving a particular mine or customer may affect our marketing efforts with respect to coal produced from the relevant mine.

For the year ended December 31, 2014, approximately 28% of our coal sales volume was shipped to our domestic customers by barge, 42% to domestic customers by rail or truck and 30% was shipped to international customers.

Each of our mines has a transloading and storage agreement with Sitran LLC (“Sitran”), a high-capacity coal transloading facility on the Ohio River near Evansville, Indiana. Sitran was contributed to us by Foresight Reserves and a member of management in February 2015. Refer to Item 13.– “Certain Relationships and Related-Party Transactions and Director Independence.” The facility currently has a single rail loop, a bottom discharge rail car unloader, stacking tubes to facilitate ground storage and blending, barge loading capabilities and throughput capacity of 25 million tons of coal per year. The terminal has the potential for a dual rail loop that would have capacity for two loaded and two empty unit trains.

Our mines also have contractual rights to throughput capacity at the Convent Marine Terminal (“CMT”), an export terminal near New Orleans owned by affiliates. Refer to Item 13.– “Certain Relationships and Related-Party Transactions and Director Independence.” CMT is designed to ship and receive commodities via rail, river barge and ocean vessel. Rail service to CMT is provided by the CN railroad. Water borne material is received and shipped via the Mississippi River. Based on recent performance, CMT has in excess of 10 million tons of coal throughput capacity per year and is currently increasing throughput capacity to 25 million tons of coal per year.

Our primary domestic customers are electric utility companies in the eastern half of the United States. The majority of our customers purchase coal for terms of one year or longer, but we also supply coal on a short-term spot basis. Our two largest customers in 2014 were Dayton Power & Light Co and Citigroup, representing approximately 12% and 11% of our total coal revenues respectively. We believe the growth of our business, our ability to compete through our low-cost structure and the diversification of our customer base helps to mitigate our exposure to the loss of any one customer. However, if these two customers or any of our largest customers were to significantly reduce their purchases of coal from us, or if we were unable to sell coal to our largest customers on terms as favorable to us as the terms under our current contracts, our results of operations may be materially adversely affected.

The international thermal coal market has also been a substantial part of our business with direct and indirect sales to end users in Europe, South America, Africa and Asia. During the years ended December 31, 2014, 2013 and 2012, export tons represented approximately 30%, 33% and 44% of tons sold, respectively. The charts below illustrate our sales mix, by destination, for the years ended December 31, 2012, 2013 and 2014.

Our management and sales force actively monitor trends in contract pricing and seek to enter into long-term coal sales contracts at favorable prices. Many of our contracts allow us to substitute coal from our other mining complexes. For 2015, we have 20.2 million tons of our projected production under contract with 26 separate customers.

The terms of our coal supply agreements result from competitive bidding and extensive negotiations with customers. Consequently, the terms of these contracts vary significantly by customer, including 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.

Most of our coal supply agreements contain provisions requiring us to deliver coal within certain ranges for specific quality characteristics such as heat content, sulfur, and ash. Failure to meet these conditions could result in substantial price reductions or suspension or termination of the contract, at the election of the customer. Although the volume to be delivered under a long-term contract is stipulated, the buyer or we may vary the timing of delivery based on certain contractual provisions. Contracts also typically contain force majeure provisions allowing for the suspension of performance by the customer or us for the duration of specified events beyond the control of the affected party, including labor disputes. Some contracts may terminate upon continuance of an event of force majeure for an extended period.

Some of our long-term contracts provide for a predetermined adjustment to the stipulated base price at times specified in the agreement or at other periodic intervals to account for changes 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 affect our costs related to performance of the agreement. Also, some of our contracts contain provisions that allow for the recovery of certain costs incurred due to modifications or changes in the interpretations or application of any applicable government statutes.

Price reopener provisions are present in several of our long-term contracts. These 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. In a limited number of agreements, failure of the parties to agree on a price under a price reopener provision can lead to termination of the contract. Under some of our contracts, we have the right to match lower prices offered to our customers by other suppliers.

The United States coal industry is highly competitive, both regionally and nationally. In the Illinois Basin, we compete primarily with coal producers such as Peabody Energy Corporation; Alliance Resource Partners, L.P.; Murray Energy Corporation; White Oak Resources LLC; Armstrong Energy Inc.; Sunrise Coal LLC and Westmoreland Resource Partners L.P. Outside of the Illinois Basin, we compete broadly with other United States-based producers of thermal coal and internationally with numerous global coal producers.

A number of factors beyond our control affect the markets in which we sell our coal. Continued demand for our coal and the prices obtained by us depend primarily on: the coal consumption patterns of the electricity industry in the United States and elsewhere around the world; the availability, location, cost of transportation and price of competing coal; and other electricity generation and fuel supply sources such as natural gas, oil, nuclear, hydroelectric and renewable energy. Coal consumption patterns are affected primarily by the demand for electricity, environmental and other governmental regulations and technological developments. The most important factors on which we compete are price, coal quality characteristics and reliability of supply.

We do not have direct employees at Foresight Energy LP. Corporate employees are employed by Foresight Energy Services LLC. Each of our operating subsidiaries has a contract in place with an affiliated contract operator for the mining and processing of all coal produced at our mines. As of December 31, 2014, through the contracts described below, our operations had approximately 888 contractor employees. None of our operations have contractor employees represented by a union.

Each of the contract mining operators, who are under common ownership, are managed by their own senior mine managers and executives. The mining operators are managed by an executive management team who are employed by Coal Field Construction Company, LLC (“Coal Field”), a variable interest entity that we have deemed an affiliate for accounting purposes. Coal Field is the entity responsible for managing our contractors and providing maintenance and construction services for the Partnership. The executive management team has on average 21 years of experience in the industry, including an average of 8 years of experience at our mining complexes. The individual mine managers managing our mines have an average of 19 years of mining experience and virtually all have a bachelor’s degree in mining, civil engineering or business administration, while some have advanced degrees in occupational safety or certifications as professional engineers. We believe each of these senior mine managers and the executive management team have the relevant experience and qualifications necessary to ensure the efficient and safe operation of each of our mines. In turn, management of the Partnership that oversees the contract mine operators has broad and extensive industry experience. Responsibilities of management of the Partnership who oversee the contract mine operators include: i) day-to-day review of the safety and environmental laws and regulations at the federal, state and local enforcement levels; ii) establishing the contractor’s production levels; and iii) approval of mine plans, operating budgets and material capital expenditures.

Certain of our operating subsidiaries are party to a Contract Mining Agreement (“Contract Mining Agreement”) and Coal Processing Agreement (“Coal Processing Agreement” and, together with the Contract Mining Agreement, the “Mining Agreements”) with their respective affiliated contractor, each of which we account for as a variable interest entity. Pursuant to the Mining Agreements, each contractor is required to furnish all manpower, parts, security services, machinery, tools, power, fuel, explosives, water, materials, supplies and all other items necessary to (i) construct, maintain and periodically rehabilitate a mine site on the premises specified in the contract; (ii) mine the premises specified in the contract by modern and efficient deep mining methods; (iii) load, deliver and transport the coal from the premises; (iv) operate and manage the coal processing and loading facility (each, a “Facility”); (v) operate the beltlines transporting raw coal into the prep plant, (vi) wash and process raw coal through the applicable Facility; (vii) at our request, blend coal; (viii) dispose, stockpile, handle, treat and/or store all coal refuse; and (ix) store, prepare, treat, manage and load our coal through the applicable Facility. Although each Mining Agreement permits us to require the contract miner to provide parts and equipment, we have not historically invoked this provision. A contractor is entitled to use all mine infrastructure and fixtures belonging to us in the performance of labor services under the applicable Mining Agreements as well as mobile, non-mobile and semi-mobile equipment located on the mine premises. A contractor has the right, with our approval, to construct, operate and maintain the prep plant, loading facility, mine premises or adjacent property owned by us, as well as such buildings, equipment,

improvements and roadways as may be required. Each Mining Agreement also provides the applicable contractor with a non-exclusive right to mine our coal on the premises in amounts designated by us.

Each Contract Mining Agreement has an initial term of one year, with the term thereafter automatically extended for successive one-year periods unless sooner terminated by us or the contractor. We have the right to terminate each Contract Mining Agreement at any time, with or without cause, by giving 10 days’ prior written notice to the contractor. Each contractor has the right to terminate its Contract Mining Agreement at any time, with or without cause, by giving us 45 days’ prior written notice.

We are required to pay each contractor its costs plus $0.01 per ton for each ton of coal mined. We are responsible for all royalties required to be paid on the coal mined from premises, all severance taxes applicable to the coal (if any), any per-ton reclamation fee or tax, any fees or taxes required to be paid under any surface coal mining laws and black lung excise tax imposed for black lung benefits. Each contractor is responsible to pay all taxes incident to the services performed under the contract, property taxes on the premises, business and occupation taxes, payroll taxes and sales and use taxes. Each contractor is also responsible and solely liable for the payment of any assessments, penalties or other fines imposed by any federal, state or local agency and for violation of any federal, state or local law or regulation arising out of the contractor’s performance of the work under the applicable Contract Mining Agreement. The employees of the contractor are not our employees and the contractor has the sole and exclusive responsibility to pay and provide benefits for such employees. Each Contract Mining Agreement also requires that the contractor maintain insurance throughout the length of the contract.

Each Coal Processing Agreement has an initial term of one year, with the term thereafter automatically extended for successive one-year periods unless sooner terminated by us or the contractor. We have the right to terminate each Coal Processing Agreement at any time, with or without cause, by giving not less than 30 days’ prior written notice to the contractor. Each contractor has the right to terminate its Coal Processing Agreement at any time, with or without cause, by giving us not less than 30 days’ prior written notice.

We are required to pay the contractor its costs plus $0.01 per ton for each ton of coal processed and loaded through the applicable Facility for which we are paid by a purchaser of coal. Each contractor is responsible to pay all taxes incident to the services performed under the contract, property taxes on the premises, business and occupation taxes, payroll taxes, and sales and use taxes. Each contractor is also responsible and solely liable for the payment of any assessments, penalties or other fines imposed by any federal, state or local agency and for violation of any federal, state or local law or regulation arising out of the contractor’s performance of the work under the applicable Coal Processing Agreement. The employees of the contractor are not our employees and the contractor has the sole and exclusive responsibility to pay and provide benefits for such employees. Each Coal Processing Agreement also requires that the contractor maintain insurance throughout the length of the contract.

Our operations are subject to a variety of U.S. federal, state and local laws and regulations, such as those relating to employee health and safety; water discharges; air emissions; plant and wildlife protection; the restoration of mining properties; the storage, treatment and disposal of wastes; remediation of contaminants; surface subsidence from underground mining and the effects of mining on surface water and groundwater conditions.

We believe that we are in material compliance with all applicable environmental, health, safety and related requirements, including all required permits and approvals. However, there can be no assurance that violations will not occur in the future; that we will be able to always obtain, maintain or renew required permits; or that changes in these requirements or their enforcement or the discovery of new conditions will not cause us to incur significant costs and liabilities in the future. Due to the nature of the regulatory programs that apply to our mining operations, which can impose liability even in the absence of fault and often involve subjective criteria, it is not reasonable to expect any coal mining operation to be free of citations. Certain of our current and historical mining operations use or have used or store regulated materials which, if released into the environment, may require investigation and remediation. Under certain permits, we are required to monitor groundwater quality on and adjacent to our sites and to develop and implement plans to minimize and correct land subsidence, as well as impacts on waterways and wetlands, caused by our mining operations. Major regulatory requirements are briefly discussed below.

In the United States, the Coal Mine Health and Safety Act of 1969, the Federal Mine Safety and Health Act of 1977 (the “1977 Act”) and the Mine Improvement and New Emergency Response Act of 2006 (“MINER Act”) impose stringent mine safety and health standards on all aspects of mining operations. In 1978, the Mine Safety and Health Administration (“MSHA”) was created to carry out the mandates of the 1977 Act and was granted enforcement authority. MSHA is authorized to inspect all underground mining operations at least four times a year and issue citations with civil penalties for the violation of a mandatory health and safety standards. MSHA review and approval is required for a number of miner safety and welfare plans including ventilation, roof control/bolting, safety training and ground control, refuse disposal and impoundments and respirable dust. Also, the State of Illinois has its own programs for mine safety and health regulation and enforcement.

Under the 1977 Act, MSHA has the authority to issue orders or citations to mine operators regardless of the degree of culpable conduct engaged in by the operator, and it must assess a penalty for each citation or order. Factors such as degree of negligence and gravity of the violation affect the amount of penalty assessed, and sometimes permit MSHA to issue orders directing withdrawal of miners from the mine or affected areas within the mine. The 1977 Act contains provisions that can impose criminal liability on the mine operator or individuals.

The MINER Act added more extensive health and safety compliance standards, and increased civil and criminal penalties. Some of the MINER Act requirements included stricter criteria for sealing off abandoned areas of mines, the addition of refuge alternatives, stricter requirements for conveyor belts, and upgrades to communication with and tracking of miners underground.

MSHA continues to promulgate rules that affect our mining operations. In March of 2013, MSHA implemented a revised Pattern of Violations (“POV”) standard. Under the revised standard, mine operators are no longer entitled to a ninety day notice of potential POV. In addition, MSHA began screening for POV by using issued citations and orders, prior to their final adjudication. If a mine is designated as having a POV, MSHA will issue an order withdrawing miners from any areas affected by violations which pose a significant and substantial (“S&S”) hazard to the health and/or safety of miners. Once a mine is in POV status, it can be removed from that status only upon (i) a complete inspection of the entire mine with no S&S enforcement actions issued by MSHA or (ii) no POV-related withdrawal orders being issued by MSHA within ninety (90) days following the mine operator being placed on POV status. However, from time to time one or more of our operations may meet the POV screening criteria, and we cannot make assurances that one or more of our operations will not be placed into POV status, which could materially and adversely affect our results of operations.

In April 2014, MSHA issued a final rule lowering certain standards for respirable dust, among other provisions. Specifically, the rule reduces the overall dust standard from 2.0 to 1.5 milligrams per cubic meter of air and cuts in half the standard from 1.0 to 0.5 for certain mine entries and miners with pneumoconiosis.

In July 2014, MSHA issued a proposed rule that would change its civil penalty criteria. The proposed rule increases the civil penalties for those violations exhibiting more than ordinary negligence. While this rule is not final, if it is implemented, it could increase the amount of civil penalties our operations pay to MSHA.

In January 2015, MSHA issued a final rule on the use of proximity detection systems on certain pieces of underground mining equipment. The rule requires, among other provisions, continuous mining machines to be equipped with electronic sensing devices

that can detect the presence of miners in proximity to the machines and then cause moving or repositioning continuous mining machines to stop before contacting a miner. The final rule has a phase in period of 8 to 36 months, depending upon the age of the continuous mining machine.

These requirements have, and will continue to have, a significant effect on our operating costs.

Under the United States Black Lung Benefits Revenue Act of 1977 and the Black Lung Benefits Reform Act of 1977, as amended in 1981, each coal mine operator must secure payment of federal black lung benefits to claimants who have been diagnosed with pneumoconiosis and are current and former employees and to a trust fund for the payment of benefits and medical expenses to claimants who last worked in the coal industry prior to July 1, 1973. The trust fund is funded by an excise tax on production sold domestically of up to $1.10 per ton for deep-mined coal and up to $0.55 per ton for surface-mined coal, neither amount to exceed 4.4% of the gross sales price.

Our contract miners are required by federal and state statutes to provide benefits to their employees for claims related to black lung, and it is a cost which they are permitted to pass onto us during the terms of their contracts.

We are subject to various U.S. federal, state and local environmental laws. Some of these laws, as discussed below, impose stringent requirements on our coal mining operations. U.S. federal and state regulations require regular monitoring of our mines and other facilities to ensure compliance. U.S. federal and state inspectors are required to inspect our mining facilities on a frequent schedule. Future laws, regulations or orders, as well as future interpretations or more rigorous enforcement of existing laws, regulations or orders, may require increases in capital and operating costs the extent of which we cannot predict.

SMCRA, which is administered by the Office of Surface Mining Reclamation and Enforcement (“OSM”), establishes mining, environmental protection and reclamation standards for all aspects of surface mining as well as many aspects of deep mining. Mine operators must obtain SMCRA permits and permit renewals from the OSM or the applicable state agency. Where state regulatory agencies have adopted federal mining programs under SMCRA, the state becomes the regulatory authority. Illinois has achieved primary control of enforcement through federal authorization.

SMCRA permit provisions include a complex set of requirements which include: coal prospecting; mine plan development; topsoil removal, storage and replacement; selective handling of overburden materials; mine pit backfilling and grading; protection of the hydrologic balance; subsidence control for underground mines; surface drainage control; mine drainage and mine discharge control and treatment; restoration to the approximate original contour; and re-vegetation. The disposal of coal refuse is also permitted under SMCRA. Both coarse refuse and slurry disposal areas require permits from the Illinois Department of Natural Resources (“IDNR”), including the disposal of slurry underground.

The mining permit application process is initiated by collecting baseline data to adequately characterize the pre-mine environmental condition of the permit area. This work includes surveys of cultural and historical resources, soils, vegetation, wildlife, assessment of surface and ground water hydrology, climatology and wetlands. In conducting this work, we collect geologic data to define and model the soil and rock structures and coal that we will mine. We develop mining and reclamation plans by utilizing this geologic data and incorporating elements of the environmental data. The mining and reclamation plan incorporates the provisions of SMCRA, state programs and other complementary environmental programs that affect coal mining. Also included in the permit application are documents defining ownership and agreements pertaining to coal, minerals, oil and gas, water rights, rights of way and surface land, and documents required of the OSM’s Applicant Violator System, including the mining and compliance history of officers, directors and principal owners of the entity.

Once a permit application is prepared and submitted to the regulatory agency, it goes through a completeness review and technical review. Public notice of the proposed permit is given that also provides for a comment period before a permit can be issued. Some SMCRA mine permits take over a year to prepare, depending on the size and complexity of the mine and may take months or years to be reviewed and issued. Regulatory authorities have considerable discretion in the timing of the permit issuance and the public and other agencies have rights to comment on and otherwise engage in the permitting process, including through intervention in the courts. Before an SMCRA permit is issued, a mine operator must submit a bond or otherwise secure the performance of reclamation obligations.

The Abandoned Mine Land Fund, which is part of SMCRA, requires a fee on all coal produced. The proceeds are used to reclaim mine lands closed or abandoned prior to SMCRA’s adoption in 1977. The fee on surface-mined coal is currently $0.28 per ton and the fee on deep-mined coal, which is applicable to our operations, is $0.12 per ton.

SMCRA stipulates compliance with many other major environmental statutes, including: the Clean Air Act; the Endangered Species Act; the CWA; RCRA and Comprehensive Environmental Response, Compensation, and Liability Act (“CERCLA”.)

Various federal and state laws, including SMCRA, require us to obtain surety bonds or other forms of financial security to secure payment of certain long-term obligations, including mine closure or reclamation costs. As of December 31, 2014, we had outstanding surety bonds of $54.8 million primarily related to these matters. Changes in these laws or regulations could require us to obtain additional surety bonds or other forms of financial security.

The Clean Air Act and comparable state laws that regulate air emissions affect coal mining operations both directly and indirectly. Direct impacts on coal mining operations may occur through Clean Air Act permitting requirements or emission control requirements relating to particulate matter, such as fugitive dust, including future regulation of fine particulate matter measuring 2.5 micrometers in diameter or smaller. The Clean Air Act indirectly affects coal mining operations by extensively regulating the air emissions of sulfur dioxide, nitrogen oxides, mercury and other compounds emitted by coal-fired electricity generating plants.

Clean Air Act requirements that may directly or indirectly affect our operations include the following:

Acid Rain. Title IV of the Clean Air Act required a two-phase reduction of sulfur dioxide emissions by electric utilities and applies to all coal-fired power plants generating greater than 25 megawatts of power. The affected electricity generators have sought to meet these requirements by, among other compliance methods, switching to lower sulfur fuels, installing pollution control devices, reducing electricity generating levels or purchasing sulfur dioxide emission allowances. We cannot accurately predict the effect of these provisions of the Clean Air Act on us in future years. We believe that implementation has resulted in increasing installations of pollution control devices as a control measure and thus, created a growing market for our higher sulfur coal.

Fine Particulate Matter. The Clean Air Act requires the Environmental Protection Agency (“EPA”) to set standards, referred to as National Ambient Air Quality Standards (“NAAQS”), for certain pollutants. Areas that are not in compliance (referred to as “non-attainment areas”) with these standards must take steps to reduce emissions levels. The EPA promulgated NAAQS for particulate matter with an aerodynamic diameter less than or equal to 10 microns, or PM10, and for fine particulate matter with an aerodynamic diameter less than or equal to 2.5 microns, or PM2.5. Meeting current or potentially more stringent new PM2.5 standards may require reductions of nitrogen oxide and sulfur dioxide emissions. Future regulation and enforcement of the new PM2.5 standard will affect many power plants and coke plants, especially coal-fired power plants and all plants in non-attainment areas. Continuing non-compliance could prevent issuance of permits to facilities within the non-attainment areas

Ozone. Significant additional emissions control expenditures will be required at coal-fired power plants and coke plants to meet the current NAAQS for ozone. Nitrogen oxides, which are a by-product of coal combustion, can lead to the creation of ozone. Accordingly, emissions control requirements for new and expanded coal-fired power plants and industrial boilers and coke plants will continue to become more demanding in the years ahead. More stringent NAAQS in the future for ozone could increase the costs of operating coal-fired power plants.

Cross-State Air Pollution Rule (“CSAPR”). The CSAPR, which was intended to replace the previously developed Clean Air Interstate Rule (“CAIR”), requires states to reduce power plant emissions that contribute to ozone or fine particle pollution in other states. Under the CSAPR, emissions reductions were to have started January 1, 2012, for SO2 and annual NOx reductions, and May 1, 2012, for ozone season NOx reductions. Several states and other parties filed suits in the United States Court of Appeals for the District of Columbia Circuit in 2011 challenging the CSAPR. On August 21, 2012, the D.C. Circuit vacated the CSAPR and ordered the EPA to continue administering CAIR, pending the promulgation of a replacement rule. It is unclear what effect, if any, CAIR will have on our operations or results. On April 29, 2014, the United States Supreme Court found that the EPA was complying with statutory requirements when it issued CSAPR and reversed the D.C. Circuit’s vacation of CSAPR. On October 23, 2014, the D.C. Circuit granted the EPA’s request to lift the stay on CSAPR. Phase 1 implementation of CSAPR is set to begin in 2015, and Phase 2 will start in 2017 provided that there are no successful challenges to the D.C. Circuit’s most recent decision. Because U.S. utilities have continued to take steps to comply with CAIR, which requires similar power plant emissions reductions, and because utilities are preparing to comply with the Mercury and Air Toxics Standards regulations which require overlapping power plant emissions reductions, the practical impact of the reinstatement of CSAPR is expected to be limited.

Mercury and Air Toxic Standards (“MATS”). On December 16, 2011, the EPA issued the MATS to reduce emissions of toxic air pollutants, including mercury, other metals and acid gases, from new and existing coal and oil fired power plants. Under the final

rule, existing power plants will have up to four years to comply with the MATS by installing or upgrading pollution controls, fuel switching, or using existing emissions controls as necessary to meet the compliance deadline. These requirements could significantly increase our customers’ costs and cause them to reduce their demand for coal, which may materially impact our results or operations.

Greenhouse Gases (“GHG”). Increasing concern about GHG, including carbon dioxide, emitted from burning coal at electricity generation plants has led to efforts at all levels of government to reduce their emissions, which could require utilities to burn less or eliminate coal in the production of electricity. Congress has considered federal legislation to reduce GHG emissions which, among other things, could establish a cap and trade system for GHG, including carbon dioxide emitted by coal burning power plants, and requirements for electric utilities to increase their use of renewable energy such as solar and wind power. Also, the EPA has taken several recent actions under the Clean Air Act to regulate GHG emissions. These include the EPA’s finding of “endangerment” to public health and welfare from GHG, its issuance in 2009 of the Final Mandatory Reporting of Greenhouse Gases Rule, which requires large sources, including coal-fired power plants, to monitor and report GHG emissions to the EPA annually starting in 2011, and issuance of its Prevention of Significant Deterioration and Title V Greenhouse Gas Tailoring Rule, which requires large industrial facilities, including coal-fired power plants, to obtain permits to emit, and to use best available control technology to curb GHG emissions. In response to a recent Supreme Court decision, the EPA is scaling back its GHG permitting program in part and plans to finalize a rule by the end of 2015 to rescind certain permits issued under the Clean Air Act triggered solely because of GHG emissions. On September 20, 2013, the EPA proposed new source performance standards for GHG for new coal and oil-fired power plants, which could require partial carbon capture and sequestration to comply. The EPA expects to issue the final regulation by mid-summer 2015. On June 2, 2014, the EPA further proposed new regulations limiting carbon dioxide emissions from existing power generation facilities. Under this proposal, nationwide carbon dioxide emissions would be reduced by 30% from 2005 levels by 2030 with a flexible interim goal. The EPA also expects to issue this final rule by mid-summer 2015 and the emission reductions are scheduled to commence in 2020. While the EPA’s actions are subject to procedural delays and legal challenges, and efforts are underway in Congress to limit or remove the EPA’s authority to regulate GHG emissions, they will remain in effect unless altered by the courts or Congress.

Regional Emissions Trading. Nine northeast and mid-Atlantic states have cooperatively developed a regional cap and trade program, the Regional Greenhouse Gas Initiative (“RGGI”), intended to reduce carbon dioxide emissions from power plants in the region. There can be no assurance at this time that this, or similar state or regional carbon dioxide cap and trade programs, in the states where our customers operate, will not adversely affect the future market for coal in the region.

Regional Haze. The EPA has initiated a regional haze program designed to protect and to improve visibility at and around national parks, national wilderness areas and international parks. This program restricts the construction of new coal-fired power plants whose operation may impair visibility at and around federally protected areas. Moreover, this program may require certain existing coal-fired power plants to install additional control measures designed to limit haze-causing emissions, such as sulfur dioxide, nitrogen oxides, volatile organic chemicals and particulate matter. These limitations could adversely affect the future market for coal.

The RCRA affects coal mining operations by establishing requirements for the treatment, storage, and disposal of hazardous wastes. Certain coal mine wastes, such as overburden and coal cleaning wastes, are exempted from hazardous waste management.

Subtitle C of the RCRA exempted fossil fuel combustion wastes from hazardous waste regulation until the EPA completed a report to Congress and made a determination on whether the wastes should be regulated as hazardous. In 2000, the EPA concluded that coal combustion wastes do not warrant regulation as hazardous under the RCRA. Following a large spill of coal ash waste at a coal burning power plant in Tennessee in June 2010, the EPA proposed two alternative sets of regulations governing the management and storage of coal ash: one would regulate coal ash and related ash impoundments at coal-fired power plants under federal regulations governing hazardous solid waste under Subtitle C of the RCRA and the other would regulate coal ash as a non-hazardous solid waste under Subtitle D. In December 2014, EPA announced that it had determined to regulate coal combustion wastes as a nonhazardous substance under Subtitle D of the RCRA. While classifying coal combustion waste as a hazardous waste under Subtitle C would have led to more stringent requirements, the new rule could still increase customers’ operating costs and may make coal less attractive for electric utilities.

In addition, environmental groups filed a notice of intent to sue the EPA for failing to update effluent limitation guidelines under the Clean Water Act for coal-fired power plants to limit discharges of toxic metals from handling of coal combustion waste. In April 2013, the EPA released its proposed revised effluent limitation guidelines to address toxic pollutants discharged from power plants, including discharges from coal ash ponds. If the EPA adopts new Clean Water Act requirements, compliance obligations for handling, transporting, storing and disposing of the material would likely increase. Potential changes to all of these rules could make coal burning more expensive or less attractive for electric utilities.

Most state hazardous waste laws exempt coal combustion waste and instead treat it as either a solid waste or a special waste. These laws may also be revised. Any costs associated with handling or disposal of coal ash as hazardous wastes would increase our customers’ operating costs and potentially reduce their ability to purchase coal. In addition, potential liability for contamination caused by the past or future use, storage or disposal of ash could substantially increase.

The CWA established in-stream water quality standards and treatment standards for wastewater discharge through the National Pollutant Discharge Elimination System (“NPDES”.) Regular monitoring, reporting requirements and performance standards are requirements of NPDES permits that govern the discharge of pollutants into water.

Total Maximum Daily Load (“TMDL”) regulations establish a process by which states may designate stream segments as “impaired” (not meeting present water quality standards). Industrial dischargers, including coal mines and plants, will be required to meet new TMDL effluent standards for these stream segments. The adoption of new TMDL regulations in receiving streams could hamper or delay the issuance of discharge and Section 404 permits, and if issued, could require new effluent limitations for our coal mines and could require more costly water treatment, which could adversely affect our coal production or results of operations. States are also adopting anti-degradation regulations in which a state designates certain water bodies or streams as “high quality.” These regulations would prohibit the diminution of water quality in these streams. Water discharged from coal mines to high quality streams will be required to meet or exceed new “high quality” standards. The designation of high quality streams at or in the vicinity of our coal mines could require more costly water treatment and could adversely affect our coal production or results of operations.

CERCLA and similar state laws affect coal mining by creating liability for the investigation and remediation of releases of regulated materials into the environment and for damages to natural resources. Under these laws, joint and several liability may be imposed on waste generators, current and former site owners or operators and others regardless of fault, for all related site investigation and remediation costs.

Mining companies must obtain numerous permits that impose strict regulations on various environmental and safety matters. These provisions include requirements for building dams; coal prospecting; mine plan development; topsoil removal, storage and replacement; protection of the hydrologic balance; subsidence control for underground mines; subsidence and surface drainage control; mine drainage and mine discharge control and treatment; and re-vegetation.

Required permits include mining and reclamation permits under the SMCRA, issued by the IDNR, and wastewater discharge, or NPDES, permits under the CWA, issued by the Illinois Environmental Protection Agency (“IEPA”.) In addition to the required permits, for surface operations, the mining companies also need to obtain air quality permits from IEPA, fill and dredge permits from the United States Army Corps of Engineers and flood plain permits from the IDNR. For refuse disposal operations, the mining companies may need to obtain impounding permits or underground slurry disposal permits from the IDNR. In addition, MSHA approval for ventilation, roof control and numerous specific surface and underground operations must be obtained and maintained. The authorization and permitting requirements imposed by these and other governmental agencies are costly and may delay development or continuation of mining operations. Due to the fact that the application review process may take years to complete and permit applications are increasingly being challenged by environmental and other advocacy groups, we may experience difficulty or delays in obtaining mining permits or other necessary approvals, or even face denials of permits altogether.

Once a permit application is prepared and submitted to the regulatory agency, it goes through a completeness review, technical review and public notice and comment period before it can be approved. Some SMCRA and CWA permits can take over a year to prepare, depending on the size and complexity of the mine and often take six months or years to receive approval. Regulatory authorities have considerable discretion in the timing of the permit issuance and the public has rights to comment on and otherwise engage in the permitting process, including through intervention in the courts.

Currently, we have the necessary permits for mining operations at each of the four complexes. Continued and expanded operations will require additional or renewed permits. These additional permits may include significant permit revisions to the SMCRA mining permit and fill and dredge permits; new NPDES, new SMCRA, new impounding, and possible CWA permits for additional refuse areas; and revisions to the SMCRA permit and a NPDES construction permit for additional bleeder shafts. Due to various and, sometimes, interrelated requirements from different agencies, it is not possible to predict an average or approximate time frame required to obtain all permits and approvals to operate new or expanded mines. In addition, expanded permitting activity in Illinois coupled with challenges from environmental groups will likely increase the various agencies’ permit and approval review time in the future. Additionally, in April 2014, the EPA proposed new rules expanding the definition of “Waters of the United States” that would expand the jurisdiction of EPA and the United States Army Corps of Engineers. This rule, if it becomes final, could impact our ability to timely obtain necessary permits.

Appeals of permits issued by the IEPA, including some CWA permits, are made to the Illinois Pollution Control Board (“IPCB”). The IPCB is an independent agency with five board members appointed by the Governor of the State of Illinois that both establishes environmental regulations under the Illinois Environmental Protection Act and decides contested environmental cases. Appeals before the IPCB are based on alleged violations of environmental laws as found in the permit and the accompanying permit record without additional testimony or evidence being taken. Appeals from the IPCB decisions are made to an Illinois appellate court.

Requests for an administrative review of permits issued by the IDNR, such as the SMCRA permits, are made to an IDNR hearing officer. Although the basis of the request for the administrative review is the alleged violations in the permit and the permit record, the administrative code rules allow for additional discovery and an evidentiary hearing. Appeals from the IDNR hearing officer’s decisions are made to an Illinois circuit court.

An investment in our common units involves risks. Limited partner interests are inherently different from the capital stock of a corporation, although many of the business risks to which we are subject are similar to those that would be faced by a corporation engaged in a similar business. You should carefully consider the risks described below, together with the other information in this Annual Report on Form 10-K, before investing in our common units. Our business, financial condition, results of operation and cash available for distribution could be materially and adversely affected by future events. In such case, we might not be able to make distributions on our common units, the trading price of our common units could decline, and you could lose all or part of your investment in, and expected return on, the common units.

A substantial or extended decline in coal prices within the coal industry or increase in the costs of mining could adversely affect our operating results and the value of our coal reserves.

Our operating results largely depend on the margins that we earn on our coal sales. Substantially all of our coal sales contracts are forward sales contracts under which customers agree to pay a specified price under their contracts for coal to be delivered in future years. The profitability of these contracts depends on our ability to adequately control the costs of the coal production underlying the contracts. Our margins reflect the price we receive for our coal over our cost of producing and transporting our coal and are impacted by many factors, including:

Substantial or extended declines in the price that we receive for our coal or increases in the costs of mining our coal could have a material adverse effect on our operating results and our ability to generate the cash flows we require to invest in our operations, satisfy our obligations and pay distributions to unitholders. To the extent our costs increase but pricing under these coal sales contracts remains fixed or declines, we will be unable to pass increasing costs on to our customers. If we are unable to control our costs, our

profitability under our forward sales contracts may be impaired and our results of operations, business and financial condition, and our ability to make distributions to our unitholders could be materially and adversely affected.

A decrease in the use of coal by electric utilities could affect our ability to sell the coal we produce.

According to the World Coal Association, in 2013, coal was used to generate over 40% of the world’s electricity needs. According to the Energy Information Administration (“EIA”), in the United States, the domestic electricity generation industry accounts for approximately 95% of domestic thermal coal consumption. The amount of coal consumed by the electricity generation industry is affected primarily by the overall demand for electricity, and environmental and other governmental regulations as well as the price and availability of renewable energy sources, including biomass, hydroelectric, wind and solar power and other non-renewable fuel sources, including natural gas and nuclear power. For example, the relatively recent low price of natural gas has resulted, in some instances, in domestic generators increasing natural gas consumption while decreasing coal consumption. Additionally, in June 2014, the EPA proposed new regulations limiting carbon dioxide emissions from existing power generation facilities. Under this proposal, nationwide carbon dioxide emissions would be reduced by 30% from 2005 levels by 2030 with a flexible interim goal. The final rule is expected to be issued in June 2015, and the emission reductions are scheduled to commence in 2020 although expected procedural delays and anticipated litigation create uncertainty regarding if and when these new regulations will take effect. Future environmental regulation of GHG emissions could accelerate the use by utilities of fuels other than coal. Domestically, state and federal mandates for increased use of electricity derived from renewable energy sources could affect demand for our coal. A number of states have enacted mandates that require electricity suppliers to rely on renewable energy sources to generate a certain percentage of their power. Such mandates, combined with other incentives to use renewable energy sources, such as tax credits, could make alternative fuel sources more competitive with coal. A decrease in coal consumption by the electricity generation industry could adversely affect the price of coal, which could negatively affect our results of operations, business and financial condition, as well as our ability to pay distributions to our unitholders.

Our mining operations are extensively regulated which imposes significant costs on us and changes to existing and potential future regulations or violations of regulations could increase those costs or limit our ability to produce coal.

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

Because we engage in longwall mining, subsidence issues are particularly important to our operations. Failure to timely secure subsidence rights or any associated mitigation agreements, could materially affect our results by causing delays or changes in our mining plan through stoppages or increased costs because of the necessity of obtaining such rights.

Because of the extensive and detailed nature of these regulatory requirements, it is extremely difficult for us and other underground coal mining companies in particular, as well as the coal industry in general, to comply with all requirements at all times. We have been cited for violations of regulatory requirements in the past and we expect to be cited for violations in the future. None of our violations to date has had a material impact on our operations or financial condition, but future violations may have a material adverse impact on our business, result of operations or financial condition. While it is not possible to quantify all of the costs of

compliance with applicable federal and state laws and associated regulations, those costs have been and are expected to continue to be significant. Compliance with these laws and regulations, and delays in the receipt of, or failure to receive or revocation of necessary government permits, could substantially increase the cost of coal mining or have a material adverse effect on our results of operations, cash flows and financial condition as well as our ability to pay distributions to our unitholders.

Extensive environmental regulations, including existing and potential future regulatory requirements relating to air emissions, 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.

The utility industry is subject to extensive regulation regarding the environmental impact of its power generation activities, particularly with respect to air emissions, which could affect demand for our coal. For example, the federal Clean Air Act and similar state and local laws extensively regulate the amount of sulfur dioxide, particulate matter, nitrogen oxides, mercury, and other compounds emitted into the air from electric power plants, which are the largest end-users of our coal. A series of more stringent requirements relating to particulate matter, ozone, haze, mercury, sulfur dioxide, nitrogen oxide and other air pollutants will, or are expected to become effective in coming years. In addition, concerted conservation efforts that result in reduced electricity consumption could cause coal prices and sales of our coal to materially decline.

More stringent air emissions limitations may require significant emissions control expenditures for many coal-fired power plants and could have the effect of making coal-fired plants less profitable. As a result, some power plants may switch to other fuels that generate less of these emissions or they may close. Any switching of fuel sources away from coal, closure of existing coal-fired plants, or reduced construction of new plants could have a material adverse effect on demand for and prices received for our coal.

It is possible that new environmental legislation or regulations may be adopted, or that existing laws or regulations may be differently interpreted or more stringently enforced, any of which could have a significant impact on our mining operations or our customers’ ability to use coal.

Recent developments in the regulation of GHG emissions and coal ash could materially adversely affect our customers’ demand for coal and our results of operations, cash flows and financial condition.

Coal-fired power plants produce carbon dioxide and other GHGs as a by-product of their operations. GHG emissions have received increased scrutiny from local, state, federal and international government bodies. Future regulation of GHGs could occur pursuant to U.S. treaty obligations or statutory or regulatory change. The EPA and other regulators are using existing laws, including the federal Clean Air Act, to limit emissions of carbon dioxide and other GHGs from major sources, including coal-fired power plants that may require the use of “best available control technology.” For example, in 2011, the EPA issued regulations, including permitting requirements, restricting GHG emissions from any new U.S. power plants, and from any existing U.S. power plants that undergo major modifications that increase their GHG emissions. In response to a recent Supreme Court decision, the EPA is scaling back its GHG permitting program in part and plans to finalize a rule by the end of 2015 to rescind certain permits issued under the Clean Air Act triggered solely because of GHG emissions. In addition, the EPA, in September 2013, also proposed new source performance standards for GHG emissions for new coal and oil-fired power plants, which could require partial carbon capture and sequestration. The EPA is expected to issue a final regulation by mid-summer 2015. In addition, in June 2013, President Obama announced additional initiatives intended to reduce greenhouse gas emissions globally, including curtailing U.S. government support for public financing of new coal-fired power plants overseas and promoting fuel switching from coal to natural gas or renewable energy sources. Global treaties are also being considered that place restrictions on carbon dioxide and other GHG emissions. On June 2, 2014, the EPA further proposed new regulations limiting carbon dioxide emissions from existing power generation facilities. Under this proposal, nationwide carbon dioxide emissions would be reduced by 30% from 2005 levels by 2030 with a flexible interim goal. The final rule is expected to be issued by mid-summer 2015 and the emission reductions are scheduled to commence in 2020. In addition, state and regional climate change initiatives to regulate GHG emissions, such as the RGGI of certain northeastern and mid-Atlantic states, the Western Climate Initiative, the Midwestern Greenhouse Gas Reduction Accord and the California Global Warming Solutions Act, either have already taken effect or may take effect before federal action. Further, governmental agencies have been providing grants or other financial incentives to entities developing or selling alternative energy sources with lower levels of GHG emissions, which may lead to more competition from those entities. There have also been several public nuisance lawsuits brought against power, coal, oil and gas companies alleging that their operations are contributing to climate change. The plaintiffs are seeking various remedies, including punitive and compensatory damages and injunctive relief. While the U.S. Supreme Court recently determined that such claims cannot be pursued under federal law, plaintiffs may seek to proceed under state common law.

In December 2014, the EPA announced that it had determined to regulate coal combustion wastes, sometimes referred to as coal ash, as a nonhazardous substance under Subtitle D of the RCRA. While classifying coal combustion waste as a hazardous waste under

Subtitle C of the RCRA would have led to more stringent requirements, the new rule could still increase customers’ operating costs and may make coal less attractive for electric utilities.

The enactment of these and other laws or regulations regarding emissions from the combustion of coal or other actions to limit such emissions, could result in electricity generators switching from coal to other fuel sources thereby reducing demand for our coal. Significant public opposition has also been raised with respect to the proposed construction of certain new coal-fueled electricity generating plants and certain new export transloading facilities due to the potential for increased air emissions. Such opposition, as well as any corporate or investor policies against coal-fired generation plants could also reduce the demand for our coal. Further, policies limiting available financing for the development of new coal-fueled power plants could adversely impact the global demand for coal in the future. The potential impact on us of future laws, regulations or other policies or circumstances will depend upon the degree to which any such laws, regulations or other policies or circumstances force electricity generators to diminish their reliance on coal as a fuel source. In view of the significant uncertainty surrounding each of these factors, it is not possible for us to reasonably predict the impact that any such laws, regulations or other policies may have on our results of operations, cash flows and financial condition as well as our ability to pay distributions to our unitholders. However, such impacts could have a material adverse effect on our results of operations, cash flows and financial condition as well as our ability to pay distributions to our unitholders.

Extensive governmental regulation pertaining to contractor safety and health imposes significant costs on our mining operations and could materially and adversely affect our results of operations.

Federal and state safety and health regulations in the coal mining industry are among the most comprehensive and pervasive systems for protection of employee safety and health affecting any U.S. industry. Compliance with these requirements imposes significant costs on us and can result in reduced productivity. New health and safety legislation, regulations and orders may be adopted that may materially and adversely affect our mining operations.

Federal and state health and safety authorities inspect our operations, and we anticipate a continued increase in the frequency and scope of these inspections. In recent years, federal authorities have also conducted special inspections of coal mines for, among other safety concerns, the accumulation of coal dust and the proper ventilation of gases such as methane. In addition, the federal government has announced that it is considering changes to mine safety rules and regulations, which could potentially result in or require additional safety training and planning, enhanced safety equipment, more frequent mine inspections, stricter enforcement practices and enhanced reporting requirements.

In addition, in March 2013, MSHA implemented a revised POV standard. Under the revised standard, mine operators are no longer entitled to a ninety day notice of potential POV. In addition, MSHA began screening for POV by using issued citations and orders, prior to their final adjudication. If a mine is designated as having a POV, MSHA will issue an order withdrawing miners from any areas affected by violations which pose a significant and substantial hazard to the health and/or safety of miners. Once a mine is in POV status, it can be removed from that status only upon (i) a complete inspection of the entire mine with no S&S enforcement actions issued by MSHA or (ii) no POV-related withdrawal orders being issued by MSHA within ninety (90) days following the mine operator being placed on POV status. Litigation testing the validity of the standard and its application by MSHA is ongoing. However, from time to time one or more of our operations may meet the POV screening criteria, and we cannot make assurances that one or more of our operations will not be placed into POV status, which could materially and adversely affect our results of operations. While our Sugar Camp operation met the criteria for POV status as of December 31, 2014, we have not received notification from MSHA that we have been deemed in a POV status.

Our contractors must compensate employees for work-related injuries. If adequate provisions for workers’ compensation liabilities were not made, our future operating results could be harmed. Also, federal law requires we contribute to a trust fund for the payment of benefits and medical expenses to certain claimants. Currently, the trust fund is funded by an excise tax on coal production of $1.10 per ton for underground coal sold domestically, not to exceed 4.4% of the gross sales price. If this tax increases, or if we could no longer pass it on to the purchasers of our coal under our coal sales agreements, our operating costs could be increased and our results could be materially and adversely affected. If new laws or regulations increase the number and award size of claims, it could materially and adversely harm our business. In addition, the erosion through tort liability of the protections we are currently provided by workers’ compensation laws could increase our liability for work-related injuries and have a material adverse effect on our results of operations, cash flows and financial condition as well as our ability to pay distributions to our unitholders.

Extensive environmental regulations, including existing and potential future regulatory requirements, pertaining to discharge of materials into the environment, including wastewater, imposes significant costs to our mining operations and could materially and adversely affect our production, cash flow and profitability.

Our mining operations are subject to numerous complex regulatory, compliance, and enforcement programs. While we believe we are in compliance with all environmental regulatory requirements, our operations have, from time to time, been issued violation notices from various agencies, including the IEPA. In July 2014, following issuance of a violation notice, we entered into a plan which resolves all outstanding violations regarding pumped mine discharges at our Sugar Camp operation and provides long-term

water treatment and disposal capacity for that operation. We believe we are currently in compliance with the plan. However, in the event this plan is not satisfactorily implemented, these or future violations may result in the assessment of fines or penalties, or, a temporary or permanent suspension of the affected mining operations. Additionally, we cannot make assurances that one or more of our operations will not receive future violation notices that result in fines, penalties, or suspension of mining activities. Such a suspension could have a material adverse effect on our results of operations, cash flows and financial condition, as well as our ability to make distributions to our unitholders.

Additionally, regulatory agencies may, from time to time, add more stringent compliance requirements to our environmental permits either by rule, or regulation or during the permit renewal process. More stringent requirements could lead to increases in costs and could materially and adversely affect our production, cash flow and profitability. For example, on April 30, 2013, citing lack of resources and the priority of other matters, the EPA denied a petition brought by environmental groups seeking to add coal mines to the Clean Air Act section 111 list of stationary source categories, which would have had the effect of regulating methane emissions from coal mines in some manner. Following the environmental groups’ challenge to EPA’s denial, the United States Court of Appeals for the District of Columbia upheld the EPA’s action in May 2014. However, the EPA could, in the future, determine to add coal mines to the list of regulated sources and impose emission limits on coal mines, which could have a significant impact on our mining operations.

We may be unable to obtain, maintain or renew permits necessary for our operations and to mine all of our coal reserves, which would materially and adversely affect our production, cash flow and profitability.

In order to develop our economically recoverable coal reserves, we must regularly obtain, maintain or renew a number of permits that impose strict requirements on various environmental and operational matters in connection with coal mining. These include permits issued by various federal, state and local agencies and regulatory bodies. Permitting rules, and the interpretations of these rules, are complex, change frequently, and are often subject to discretionary interpretations by regulators, all of which may make compliance more difficult or impractical and could result in the discontinuance of mine development or the development of future mining operations. The public, including non-governmental organizations, anti-mining groups and individuals, have certain statutory rights to comment upon and submit objections to requested permits and environmental impact statements prepared in connection with applicable regulatory processes, and otherwise engage in the permitting process, including bringing citizens’ claims to challenge the issuance or renewal of permits, the validity of environmental impact statements or performance of mining activities. Our mining operations are currently, and may become in the future, subject to legal challenges before administrative or judicial bodies contesting the validity of our environmental permits under SMCRA and the CWA, among other statutory provisions. Accordingly, required permits may not be issued in a timely fashion or renewed at all, or permits issued or renewed may not be maintained, may be challenged or may be conditioned in a manner that may restrict our ability to efficiently and economically conduct our mining activities, any of which would materially reduce our production, cash flow, and profitability as well as our ability to pay distributions to our unitholders.

We make no assurances that we will be able to obtain, maintain or renew any of the governmental permits that we need to continue developing our proven and probable coal reserves. Further, 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 and to human health and safety that would further regulate and tax the coal industry may also require us to change operations significantly or incur increased costs. For example, in March 2014, the EPA announced a proposed rule expanding the definition of “Waters of the United States” that would expand the jurisdiction of the EPA and the United States Army Corps of Engineers to regulate waters not previously regulated. This rule, if it becomes final, could impact our ability to timely obtain necessary permits. Such changes could have a material adverse effect on our financial condition and results of operations as well as our ability to pay distributions to our unitholders.

In March 2014, the Illinois State Attorney General, the Illinois Department of Natural Resources and others entered into an order which has potentially far-reaching effects on the permitting process for mines in Illinois. While the final rules have yet to be promulgated, and thus the impact on the permitting process cannot yet be determined, it could have the effect of extending the permit review and approval process. The inability to conduct mining operations or obtain, maintain or renew permits may have a material adverse effect on our results of operations, business and financial position, as well as the ability to pay distributions to our unitholders.

Substantially all of our coal is shipped through arrangements with, and are subject to minimum volume requirements that are due regardless of whether coal is actually shipped or mined.

Substantially all of the coal that our operating companies ship and will ship are through contractual arrangements that have minimum volume requirements, including certain contractual arrangements with affiliates. Failure to meet those requirements could result in liquidated damages. If our operations do not meet the minimum volume requirements then we could suffer from a shortage of cash due to the ongoing requirement to pay minimum payments despite a lack of shipping and the associated sales revenue. As a result,

our results of operations, business and financial condition, as well as our ability to pay distributions to our unitholders may be materially adversely affected.

Our revenues and operating profits could be negatively impacted if we are unable to extend existing agreements at comparable pricing or enter into new agreements due to competition, environmental regulations affecting our customers’ changing coal purchasing patterns or other variables.

We compete with other coal suppliers when renewing expiring agreements or entering into new agreements. If we cannot renew these coal supply agreements at comparable pricing or find alternate customers willing to purchase our coal, our revenue and operating profits could suffer. Our customers may decide not to extend existing agreements or enter into new long-term contracts or, in the absence of long-term contracts, may decide to purchase fewer tons of coal than in the past or on different terms, including under different pricing terms or may decide not to purchase at all. Any decrease in demand may cause our customers to delay negotiations for new contracts or request lower pricing terms or seek coal from other sources. Furthermore, uncertainty caused by laws and regulations affecting electric utilities could deter our customers from entering into long-term coal supply agreements. Some long-term contracts contain provisions for termination due to environmental regulatory changes if such changes prohibit utilities from burning the contracted coal. In addition, a number of our long-term contracts are subject to price re-openers. If market prices are lower than the existing contract price, pricing for these contracts could reset to lower levels.

Competition within the coal industry may adversely affect our ability to sell coal and excess production capacity in the industry could put downward pressure on coal prices.

We compete with other producers primarily on the basis of price, coal quality, transportation cost and reliability of delivery. We cannot assure you that competition from other producers will not adversely affect us in the future. The coal industry has experienced consolidation in recent years, including consolidation among some of our major competitors. We cannot assure you that the result of current or further consolidation in the industry will not adversely affect us. In addition, potential changes to international trade agreements, trade concessions or other political and economic arrangements may benefit coal producers operating in countries other than the U.S., where our mining operations are currently located. We cannot assure you that we will be able to compete on the basis of price or other factors with companies that in the future may benefit from favorable trading or other arrangements. We compete directly for domestic and international coal sales with numerous other coal producers located in the U.S. and internationally, in countries such as Australia, China, India, South Africa, Indonesia, Russia and Colombia. The price of coal in the markets into which we sell our coal is also influenced by the price of coal in the markets in which we do not sell our coal because significant oversupply of coal from other markets could materially reduce the prices we receive for our coal. Increases in coal prices could encourage the development of expanded capacity by new or existing coal producers, which could result in lower coal prices. As a result, our results of operations, business and financial condition, as well as our ability to pay distributions to our unitholders may be materially adversely affected.

Global economic conditions, or economic conditions in any of the industries in which our customers operate, and continued uncertainty in financial markets may have material adverse impacts on our business and financial condition that we cannot predict.

If economic conditions or factors that negatively affect the economic health of the U.S., Europe or Asia worsen, our revenues could be reduced and thus adversely affect our results of operations. These markets have historically experienced disruptions, relating to volatility in security prices, diminished liquidity and credit availability, rating downgrades of certain investments and declining valuations of others, failure and potential failures of major financial institutions, high unemployment rates and increasing interest rates. If these developments continue or worsen it may adversely affect the ability of our customers and suppliers to obtain financing to perform their obligations to us. If the economic impact of the current downturn continues to impact foreign markets disproportionately, global currencies will continue to weaken against the U.S. dollar. This would impact our ability to continue exporting our coal by making it more expensive for foreign buyers. We believe that deterioration or a prolonged period of economic weakness will have an adverse impact on our results of operations, business and financial condition, as well as our ability to pay distributions to our unitholders.

We are involved in legal proceedings that if determined adversely to us, could significantly impact our profitability, financial position or liquidity.

We are, and from time to time may become, involved in various legal proceedings that arise in the ordinary course of business. Some lawsuits seek fines or penalties and damages in very large amounts, or seek to restrict our business activities. In particular, we are subject to legal proceedings relating to our receipt of and compliance with permits under the SMCRA and the CWA and to other legal proceedings relating to environmental matters involving current and historical operations, ownership of land or permitting. It is currently unknown what the ultimate resolution of these proceedings will be, but these proceedings could have a material adverse effect on our results of operations, cash flows and financial condition as well as our ability to make distributions to our unitholders.

Federal or state regulatory agencies have the authority to order certain of our mines to be temporarily or permanently closed under certain circumstances, which could materially and adversely affect our ability to meet our customers’ demands.

Federal or state regulatory agencies, including MSHA, IDNR and IEPA, have the authority under certain circumstances following significant health, safety or environmental incidents or pursuant to permitting authority to temporarily or permanently close one or more of our mines. If this occurred, we may be required to incur capital expenditures and/or additional expenses to re-open the mine. In the event that these agencies cause us to close one or more of our mines, our coal sales contracts generally permit us to issue force majeure notices which suspend our obligations to deliver coal under such contracts. However, our customers may challenge our issuances of force majeure notices in connection with these closures. If these challenges are successful, we may have to purchase coal from third-party sources, if available, to fulfill these obligations, incur capital expenditures to re-open the mine or negotiate settlements with the customers, which may include price reductions, the reduction of commitments or the extension of time for delivery or termination of such customers’ contracts. Any of these actions could have a material adverse effect on our results of operations, cash flows and financial condition as well as our ability to pay distributions to our unitholders.

Our operations may impact the environment or cause exposure to hazardous substances, and our properties may have environmental contamination, which could result in material liabilities to us.

Certain of our coal mining operations use or have used hazardous and other regulated materials and have generated hazardous wastes. In addition, one of our locations was used for coal mining involving hazardous materials prior to our involvement with, or operation of, such location. We may be subject to claims under federal and state statutes or common law doctrines for penalties, toxic torts and other damages, as well as for natural resource damages and for the investigation and remediation of soil, surface water, groundwater, and other media under laws such as the CERCLA, commonly known as Superfund, or the Clean Water Act. Such claims may arise, for example, out of current, former or threatened conditions at sites that we currently own or operate as well as at sites that we and companies we acquired owned or operated in the past, or sent waste to for treatment or disposal, and at contaminated sites that have always been owned or operated by third parties.

We have used coal ash for reclamation at our Macoupin mine. On December 19, 2014, the EPA issued a final rule concerning disposal and beneficial use of coal ash. In the final rule, the EPA determined to regulate coal ash as a nonhazardous material under Subtitle D of the RCRA. The EPA also clarified the definition of beneficial use of coal ash. While these requirements are less stringent than the proposed rule treating coal ash as a hazardous material under Subtitle C of the RCRA, we can make no assurances that the new rule will not increase our costs for the use of coal ash at Macoupin.

Failure to meet certain provisions in our coal supply agreements could result in economic penalties.

Most of our coal supply agreements contain provisions requiring us to deliver coal meeting quality thresholds for certain characteristics such as heat value, sulfur content, ash content, hardness and ash fusion temperature. Failure to meet these specifications could result in economic penalties, including price adjustments, purchasing replacement coal in a higher-priced open market, rejection of deliveries or termination of the contracts. In some of the contract price adjustment provisions, failure of the parties to agree on price adjustments may allow either party to terminate the contract.

Many agreements also contain provisions that permit the parties to adjust the contract price upward or downward for specific events, including changes in the laws regulating the timing, production, sale or use of coal. Moreover, a limited number of these agreements permit the customer to terminate the agreement if transportation costs increase substantially or, in the event of changes in regulations affecting the coal industry, such changes increase the price of coal beyond specified amounts. Additionally, a number of agreements provide that customers may terminate the agreement in the event a new or amended environmental law or regulation prevents or restricts the customer from utilizing coal supplied by us and/or requires material additional capital or operating expenditures to utilize such coal.

The loss of, or significant reduction in, purchases by our largest customers could adversely affect our results of operations.

For the year ended December 31, 2014, we derived approximately 11% of our total coal sales from one customer and 12% from another customer. Negotiations to extend existing agreements or enter into long-term agreements with these and other customers may not be successful, and such customers may not continue to purchase coal from us. If these two customers or any of our top customers were to significantly reduce their purchases of coal from us, or if we were unable to sell coal to our top customers on terms as favorable to us as the terms under our current contracts, our results of operations, business and financial condition, as well as our ability to pay distributions to our unitholders may be materially adversely affected.

Certain of our customers may seek to defer contracted shipments of coal which could affect our results of operations and liquidity.

From time to time, certain customers have sought and others may seek to delay shipments or request deferrals under existing agreements. There is no assurance that we will be able to resolve existing and potential deferrals on favorable terms, or at all. Any

such deferrals may have an adverse effect on our business, results of operations and financial condition, as well as our ability to pay distributions to our unitholders.

We may not be able to obtain equipment, parts and raw materials in a timely manner, in sufficient quantities or at reasonable costs to support our coal mining and transportation operations.

We use equipment in our coal mining and transportation operations such as continuous miners, conveyors, shuttle cars, rail cars, locomotives, roof bolters, shearers and shields. We procure this equipment from a concentrated group of suppliers, and obtaining this equipment often involves long lead times. Occasionally, demand for such equipment by mining companies can be high and some types of equipment may be in short supply. Delays in receiving or shortages of this equipment, as well as the raw materials used in the manufacturing of supplies and mining equipment, which, in some cases, do not have ready substitutes, or the cancellation of our supply contracts under which we obtain equipment and other consumables, could limit our ability to obtain these supplies or equipment. In addition, if any of our suppliers experiences an adverse event, or decides to no longer do business with us, we may be unable to obtain sufficient equipment and raw materials in a timely manner or at a reasonable price to allow us to meet our production goals and our revenues may be adversely impacted. We use considerable quantities of steel in the mining process. If the price of steel or other materials increases substantially or if the value of the U.S. dollar declines relative to foreign currencies with respect to certain imported supplies or other products, our operating expenses could increase. Any of the foregoing events could materially and adversely impact our results of operations, business and financial condition as well as our profitability and our ability to pay distributions to our unitholders.

The development of a longwall mining system is a challenging process that may take longer and cost more than estimated, or not be completed at all.

The full development of our reserve base may not be achieved. We may encounter adverse geological conditions or delays in obtaining, maintaining or renewing required construction, environmental or operating or mine design permits. Construction delays cause reduced production and cash flow while certain fixed costs, such as minimum royalties and debt payments, must still be paid on a predetermined schedule.

Our business requires substantial capital expenditures and we may not have access to the capital required to reach full development of 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. While a significant amount of capital expenditures required to build-out our mines has been spent, 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 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. 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.

Major equipment and plant failures could reduce our ability to produce and ship coal and materially and adversely affect our results of operations.

We depend on several major pieces of mining equipment and preparation plants to produce and ship our coal, including, but not limited to, longwall mining systems, preparation plants, and transloading facilities. If any of these pieces of equipment or facilities suffered major damage or were destroyed by fire, abnormal wear, flooding, incorrect operation, or otherwise, we may be unable to replace or repair them in a timely manner or at a reasonable cost which would impact our ability to produce and ship coal and materially and adversely affect our results of operations, business and financial condition and our ability to pay distributions to our unitholders.

We face numerous uncertainties in estimating our economically recoverable coal reserves.

Coal is economically recoverable when the price at which coal can be sold exceeds the costs and expenses of mining and selling the coal. Forecasts of our future performance are based on, among other things, estimates of our recoverable coal reserves. We base our reserve information on engineering, economic and geological data assembled and analyzed by third parties and our staff, which includes various engineers. The reserve estimates as to both quantity and quality are updated from time to time to reflect production of coal from the reserves and new drilling or other data received. There are numerous uncertainties inherent in estimating quantities and qualities of coal and costs to mine recoverable reserves, including many factors beyond our control. Estimates of economically

recoverable coal reserves necessarily depend upon a number of variable factors and assumptions, any one of which may, if inaccurate, result in an estimate that varies considerably from actual results. These factors and assumptions include:

As a result, actual coal tonnage recovered from identified reserve areas or properties and revenues and expenditures with respect to our production from reserves may vary materially from estimates. These estimates thus may not accurately reflect our actual reserves. Any material inaccuracy in our estimates related to our reserves could result in lower than expected revenues, higher than expected costs or decreased profitability which could materially adversely affect our results of operations, business and financial condition as well as our ability to pay distributions to our unitholders.

Some of our customers blend our coal with coal from other sources, making our sales dependent upon our customers locating additional sources of coal.

Our coal’s characteristics, particularly the sulfur or chlorine content, are such that many of our customers blend our coal with other purchased supplies of coal before burning it in their boilers. Some of our current or future coal sales may therefore be dependent in part on those customers’ ability to locate additional sources of coal with offsetting characteristics which may not be available in the future on terms that render the customers’ overall cost of blended coal economic. A loss of business from such customers may materially adversely affect our results of operations, business and financial condition, as well as our ability to pay distributions to our unitholders.

Our operations are subject to risks, some of which are not insurable, and we cannot assure you that our existing insurance would be adequate in the event of a loss.

We maintain insurance to protect against risk of loss but our coverage is subject to deductibles and specific terms and conditions. We cannot assure you that we will have adequate coverage or that we will be able to obtain insurance against certain risks, including certain liabilities for environmental pollution or hazards. We cannot assure you that insurance coverage will be available in the future at commercially reasonable costs, or at all, or that the amounts for which we are insured or that we may receive, or the timing of any such receipt, will be adequate to cover all of our losses. Uninsured events may adversely affect our results of operations, business and financial condition, as well as our ability to pay distributions to our unitholders.

We have future mine closure and reclamation obligations the timing of and amount for which are uncertain. In addition, our failure to maintain required financial assurances could affect our ability to secure reclamation and coal lease obligations, which could adversely affect our ability to mine or lease the coal.

In view of the uncertainties concerning future mine closure and reclamation costs on our properties, the ultimate timing and future costs of these obligations could differ materially from our current estimates. We estimate our asset retirement obligations for final reclamation and mine closure based upon detailed engineering calculations of the amount and timing of the future cash for a third party to perform the required work. Spending estimates are escalated for inflation and market risk premium, and then discounted at the credit-adjusted, risk-free rate. Our estimates for this future liability are subject to change based on new or amendments to existing applicable laws and regulations, the nature of ongoing operations and technological innovations. Although we accrue for future costs in our consolidated balance sheets, we do not reserve cash in respect of these obligations or otherwise fund these obligations in advance. As a result, we will have significant cash outlays when we are required to close and restore mine sites that may, among other things, affect our ability to satisfy our obligations under our indebtedness and other contractual commitments and pay distributions to unitholders. We cannot assure you that we will be able to obtain financing on satisfactory terms to fund these costs, or at all.

In addition, regulatory authorities require us to provide financial assurance to secure, in whole or in part, our future reclamation projects. The amount and nature of the financial assurances are dependent upon a number of factors, including our financial condition and reclamation cost estimates. Changes to these amounts, as well as the nature of the collateral to be provided, could significantly increase our costs, making the maintenance and development of existing and new mines less economically feasible. Currently, the security we provide consists of surety bonds. The premium rates and terms of the surety bonds are subject to annual renewals. Our failure to maintain, or inability to acquire, surety bonds or other forms of financial assurance that are required by applicable law, contract or permit could adversely affect our ability to operate. That failure could result from a variety of factors including the lack of availability, higher expense or unfavorable market terms of new surety bonds or other forms of financial assurance. There can be no guarantee that we will be able to maintain or add to our current level of financial assurance. Additionally, any capital resources that we do utilize for this purpose will reduce our resources available for our operations and commitments as well as our ability to pay distributions to our unitholders.

Defects in title or loss of any leasehold interests in our properties could limit our ability to conduct mining operations on these properties or result in significant unanticipated costs.

A substantial amount of our coal reserves are leased or subleased from affiliates. A title defect or the loss of any lease upon expiration of its term, upon a default or otherwise, could adversely affect our ability to mine the associated reserves or process the coal that we mine. Title to most of our owned or leased properties and mineral rights is not usually verified until we make a commitment to mine a property, which may not occur until after we have obtained necessary permits and completed exploration of the property. In some cases, we rely on title information or representations and warranties provided by our lessors or grantors. Our right to mine certain of our reserves has in the past been, and may again in the future be, adversely affected if defects in title, boundaries or other rights necessary for mining exist or if a lease expires. Any challenge to our title or leasehold interests could delay the mining of the property and could ultimately result in the loss of some or all of our interest in the property. From time to time we also may be in default with respect to leases for properties on which we have mining operations. In such events, we may have to close down or significantly alter the sequence of such mining operations which may adversely affect our future coal production and future revenues. If we mine on property that we do not own or lease, we could incur liability for such mining and be subject to regulatory sanction and penalties.

In order to obtain, maintain or renew leases or mining contracts to conduct our mining operations on property where these defects exist, we may in the future have to incur unanticipated costs. In addition, we may not be able to successfully negotiate new leases or mining contracts for properties containing additional reserves, or maintain our leasehold interests in properties where we have not commenced mining operations during the term of the lease. Some leases have minimum production requirements. As a result, our results of operations, business and financial condition, as well as our ability to pay distributions to our unitholders may be materially adversely affected.

A substantial amount of our coal reserves are leased or subleased and are subject to minimum royalty payments that are due regardless of whether coal is actually mined.

A substantial amount of the reserves that our operating companies lease are subject to minimum royalty payments, including those leases with affiliates. Failure to meet minimum production requirements could result in losses of prepaid royalties and, in some rare cases, could result in a loss of the lease itself. If certain operations do not meet production goals then we could suffer from a shortage of cash due to the ongoing requirement to pay minimum royalty payments despite a lack of production and the associated sales revenue. As a result, our results of operations, business and financial condition, as well as our ability to pay distributions to our unitholders may be materially adversely affected.

Significant increases in, or the imposition of new, taxes we pay on the coal we produce could materially and adversely affect our results of operations.

All of our mining operations are in Illinois. If Illinois was to impose a state severance tax or any other tax applicable solely to our Illinois operations, we may be significantly impacted and our results of operations, business and financial condition, as well as the ability to pay distributions to our unitholders could be materially and adversely affected. Any imposition of Illinois state severance tax or any county tax could disproportionately impact us relative to our competitors that are more geographically diverse.

A shortage of skilled mining labor in the U.S. could decrease our labor productivity and increase our labor costs, which would adversely affect our profitability.

Efficient coal mining using complex and sophisticated techniques and equipment requires skilled laborers proficient in multiple mining tasks, including mining equipment maintenance. Any shortage of skilled mining labor reduces the productivity of experienced employees who must assist in training unskilled employees. If a shortage of experienced labor occurs, it could have an adverse impact

on our labor productivity and costs and our ability to expand production in the event there is an increase in the demand for our coal, which could adversely affect our results of operations, business and financial condition, as well as our ability to pay distributions to our unitholders.

We rely exclusively on our contract mining operators to operate our mines pursuant to contract mining agreements which set forth the rights and obligations of both parties. In addition, these contract mining operators rely exclusively on our subsidiaries for their work. These contract mining operators are all owned by the same parent company. The Partnership has the ability to control certain long-term and other strategic decisions related to each of our contract mining operators. We account for each of these operators as a “variable interest entity,” meaning that, among other things, each does not have sufficient equity to finance its activities without additional financial support and its respective equity holders do not have the ability to exert control over those activities which most significantly impact its economic performance. If the Partnership were to terminate a contract mining agreement with one operator, there is no assurance that the parent of the contract mining operators would not choose to cause its other related entities to terminate their respective agreements with another or all of our mines. While the coal mining agreements do not contain any provisions which inhibit or prohibit us from directly hiring the contractor workforce, there can be no assurance that we would be able to hire the workforce previously employed by the operators, or find properly trained replacement contractors, or employees, quickly, on as favorable terms, or at all.

Although we would receive at least 30 days’ notice of termination under the contract mining and coal processing agreements, there can be no assurance that we would be able to hire the workforce previously employed by the operators, or find properly trained replacement contractors, or employees, quickly. If we were unable to hire a workforce as highly skilled, trained, or efficient, in a condensed time period, or within the geographical proximity of our mines, we could experience a material adverse effect on our results of operations, business and financial condition, as well as our ability to pay distributions to our unitholders. Moreover, the need to acquire a large workforce of trained replacements, whether by contractor or otherwise, would tend to drive up labor costs and may, even if successful, cause a material adverse effect on our results of operations, business and financial condition, as well as our ability to pay distributions to our unitholders.

There can also be no assurances that our contract operators will renew their respective contracts, or that they will renew these contracts on similar terms or terms that are favorable to us. While we currently believe that these affiliate contracts are on terms that are fair and reasonable to us, we cannot assure you that any future modification, amendment or extension of these affiliate contracts will not provide for terms that are more favorable to our affiliates. Any non-renewal or renewal on terms not as favorable to us could have a material adverse impact on our results of operations, business and financial condition, as well as our ability to pay distributions to unitholders.

Our dependence on our operators to meet day-to-day health, safety, and environmental standards to which we, and they, are bound presents a risk to our unitholders. While we monitor our operators’ compliance with health, safety, or environmental standards, through reports, and as needed inspections, a contractor’s failure to meet health, safety or environmental standards or failure to comply with all applicable laws and regulations could have a material adverse effect on our results of operations, business, and financial condition, as well as our ability to pay distributions to our unitholders.

Our dependence on our operators to meet day-to-day productive and quality standards to which we are bound through our coal sales agreements also presents a risk to our unitholders. While we monitor our operators’ performance towards meeting our production targets and quality standards, through reports, and as-needed inspections, a contractor’s failure to produce the quality or quantity of coal required by our coal supply agreements could have a material adverse effect on our results of operations, business, and financial condition, as well as our ability to pay distributions to unitholders.

Our ability to operate our mines efficiently and profitably could be impaired if we lose, or fail to continue to attract, key qualified operators.

We manage our business with a key mining operator at each location. As our business develops and expands, we believe that our future success will depend greatly on our continued ability to attract and retain highly skilled and qualified operators and contractors. We cannot be certain that we will be able to find and retain qualified operators or that they will be able to attract and retain qualified contractors in the future. Failure to retain or attract key operators could have a material adverse effect on our results of operations, business and financial condition, as well as our ability to pay distributions to our unitholders.

We operate our mines with a workforce that is employed exclusively by our affiliated operators. While none of our operators’ employees are members of unions, our workforce may not remain non-union in the future.

None of our operators’ employees are represented under collective bargaining agreements. However, that workforce may not remain non-union in the future, and proposed legislation, could, if enacted, make union organization more likely. If some or all of our

current operations were to become unionized, it could adversely affect our productivity, increase our labor costs and increase the risk of work stoppages at our mining complexes. In addition, even if we remain non-union, our operations may still be adversely affected by work stoppages at our facilities or at unionized companies, particularly if union workers were to orchestrate boycotts against our contractors.

Failures of contractor-operated sources to fulfill the delivery terms of their contracts with us could adversely affect our operations and reduce our profitability.

Within our normal mining operations, we utilize contract operators for all of our coal production. These contract operators are owned by affiliated entities that have engaged in business with us and our affiliates, including other operations for The Cline Group, Foresight Reserves’ controlling member. However, there is no assurance that these relationships will continue or continue on terms that are reasonably acceptable to us. In addition, these contract operators may determine that other operations within The Cline Group are better or more profitable for them, which may lead to conflicts of interest. To the extent this was to occur, and we are unable to adequately replace their services, our results of operations, business and financial condition, as well as our ability to pay distributions to our unitholders, could be materially adversely affected.

Our contract operators pass their costs to us. Our profitability or exposure to loss on transactions or relationships such as these is dependent upon a variety of factors, including the reliability of the operator; the cost and financial viability of the contractor; our willingness to reimburse temporary cost increases experienced by the operator our ability to pass on operator cost increases to customers; our ability to substitute, when economical, third-party coal sources with internal production or coal purchased in the market; and other factors. If any of the contract operators with whom we contract go bankrupt or were otherwise unavailable to provide their services, our results of operations, business and financial condition, as well as our ability to pay distributions to our unitholders could be materially affected.

Our ability to operate our business effectively could be impaired if we fail to attract and retain key personnel.

Our ability to operate our business and implement our strategies depends, in part, on the continued contributions of our executive officers and other key employees. The loss of any of our key senior executives could have a material adverse effect on our business unless and until we find a replacement. A limited number of persons exist with the requisite experience and skills to serve in our senior management positions. We may not be able to locate or employ qualified executives on acceptable terms. In addition, we believe that our future success will depend on our continued ability to attract and retain highly skilled personnel with coal industry experience. Competition for these persons in the coal industry is intense and we may not be able to successfully recruit, train or retain qualified managerial personnel. We may not be able to continue to employ key personnel or attract and retain qualified personnel in the future. Our failure to retain or attract key personnel could have a material adverse effect on our ability to effectively operate our business.

Coal mining operations are subject to inherent risks and are dependent on many factors and conditions beyond our control, any of which may adversely affect our productivity and our financial condition.

Our mining operations, including our transportation infrastructure, are influenced by changing conditions that can affect the safety of our workforce, production levels, delivery of our coal and costs for varying lengths of time and, as a result, can diminish our revenues and profitability. In particular, underground mining and related processing activities present inherent risks of injury to persons and damage to property and equipment. A shutdown of any of our mines or prolonged disruption of production at any of our mines or transportation of our coal to customers would result in a decrease in our revenues and profitability, which could be material. Certain factors affecting the production and sale of our coal that could result in decreases in our revenues and profitability include:

These risks, conditions and events could (1) result in: (a) damage to, or destruction of value of, our coal properties, our coal production or transportation facilities, (b) personal injury or death, (c) environmental damage to our properties or the properties of others, (d) delays or prohibitions on mining our coal or in the transportation of coal, (e) monetary losses and (f) potential legal liability; and (2) could have a material adverse effect on our operating results and our ability to generate the cash flows we require to invest in our operations and satisfy our debt obligations. Our insurance policies only provide limited coverage for some of these risks and will not fully cover these risks. A significant mine accident could potentially cause a mine shutdown, and could have a substantial adverse impact on our results of operations, financial condition or cash flows, as well as our ability to pay distributions to our unitholders.

The availability or reliability of current transportation facilities could affect the demand for our coal or temporarily impair our ability to supply coal to our customers. In addition, our inability to expand our transportation capabilities and options could further impair our ability to deliver coal efficiently to our customers.

We depend upon rail, barge, ocean-going vessels and port facilities to deliver coal to customers. Disruption of these transportation services because of weather-related problems, infrastructure damage, strikes, lock-outs, lack of fuel or maintenance items, transportation delays, lack of rail or port capacity or other events could temporarily impair our ability to supply coal to customers and thus could adversely affect our results of operations, cash flows and financial condition, as well as our ability to pay distributions to our unitholders.

Additionally, if there are disruptions of the transportation services provided by the railroad and we are unable to find alternative transportation providers to ship our coal, our business and profitability could be adversely affected. While we currently have contracts in place for transportation of coal from our facilities and have continued to develop alternative transportation options, there is no assurance that we will be able to renew these contracts or to develop these alternative transportation options on terms that remain favorable to us. Any failure to do so could have a material adverse impact on our financial position and results of operations as well as our ability to pay distributions to our unitholders.

Significant increases in transportation costs could make our coal less competitive when compared to other fuels or coal produced from other regions.

Transportation costs represent a significant portion of the total cost of coal for our customers and the cost of transportation is an important factor in a customer’s purchasing decision. Increases in transportation costs, including increases resulting from emission control requirements and fluctuations in the price of diesel fuel, could make coal a less competitive source of energy when compared to other fuels such as natural gas or could make our coal less competitive than coal produced in other regions of the U.S. or abroad.

Significant decreases in transportation costs could result in increased competition from coal producers in other parts of the country and from abroad, including coal imported into the U.S. Coordination of the many eastern loading facilities, the large number of small shipments, terrain and labor issues all combine to make shipments originating in the eastern U.S. inherently more expensive on a per ton-mile basis than shipments originating in the western U.S. Historically, high coal transportation rates and transportation constraints from the western coal producing areas into eastern U.S. markets limited the use of western coal in those markets. However, a decrease in rail rates or an increase in rail capacity from the western coal producing areas to markets served by Eastern U.S. producers could create major competitive challenges for eastern producers. Increased competition due to changing transportation costs could have an adverse effect on our results of operations, business and financial condition, as well as our ability to pay distributions to our unitholders.

Our ability to mine and ship coal may be affected by adverse weather conditions, which could have an adverse effect on our revenues.

Adverse weather conditions can impact our ability to mine and ship our coal and our customers’ ability to take delivery of our coal. Lower than expected shipments by us during any period could have an adverse effect on our revenues. In addition, severe

weather may affect our ability to conduct our mining operations and severe rain, ice or snowfall may affect our ability to load and transport coal. If we are unable to conduct our operations due to severe weather, it could have an adverse effect on our results of operations, business and financial condition, as well as our ability to pay distributions to our unitholders.

We sell a portion of our uncommitted tons in the spot market which is subject to volatility.

We derive a portion of our revenue from coal sales in the spot market, typically defined as contracts with terms of less than one year. The pricing in spot contracts is significantly more volatile than pricing through long-term coal supply agreements because it is subject to short-term demand swings. If spot market pricing for coal is unfavorable, this volatility could materially adversely affect our results of operations, business and financial condition, as well as our ability to pay distributions to our unitholders.

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

Our ability to receive payment for coal sold and delivered depends on the continued creditworthiness of our customers. Many utilities have sold their power plants to non-regulated affiliates or third parties that may be less creditworthy, thereby increasing the risk we bear on payment default. These new power plant owners may have credit ratings that are below investment grade. In addition, some of our customers have been adversely affected by the current economic downturn, which may impact their ability to fulfill their contractual obligations. Competition with other coal suppliers could force us to extend credit to customers and on terms that could increase the risk we bear on payment default. We also have contracts to supply coal to energy trading and brokering customers under which those customers sell coal to end users. If the creditworthiness of any of our energy trading and brokering customers declines, we may not be able to collect payment for all coal sold and delivered to or on behalf of these customers. An inability to collect payment from these counterparties may materially adversely affect our results of operations, business and financial condition, as well as our ability to pay distributions to our unitholders.

All of our coal and controlled reserves are in Illinois making us vulnerable to risks associated with operating in a single geographic area.

Because we operate exclusively in Illinois, any disruptions to our operations due to adverse geographical conditions or changes to the Illinois regulatory environment could significantly impact our operations, reduce our sales of coal and adversely affect our results of operation and financial condition, as well as our ability to pay distributions to our unitholders.

Terrorist attacks and threats, escalation of military activity in response to such attacks or acts of war may negatively affect our business, financial condition and results of operations.

Terrorist attacks and threats, escalation of military activity in response to such attacks or acts of war may negatively affect our business, financial condition and results of operations. Our business is affected by general economic conditions, fluctuations in consumer confidence and spending, and market liquidity, which can decline as a result of numerous factors outside of our control, such as terrorist attacks and acts of war. Future terrorist attacks against U.S. targets, rumors or threats of war, actual conflicts involving the U.S. or its allies, or military or trade disruptions affecting our customers could cause delays or losses in transportation and deliveries of coal to our customers, decreased sales of our coal and extension of time for payment of accounts receivable from our customers. Strategic targets such as energy-related assets may be at greater risk of future terrorist attacks than other targets in the U.S. It is possible that any, or a combination, of these occurrences could have a material adverse effect on our business, financial condition and results of operations, as well as our ability to pay distributions to our unitholders.

A cyber incident could result in information theft, data corruption, operational disruption and/or financial loss.

We have become increasingly dependent upon digital technologies, including information systems, infrastructure and cloud applications and services, to operate our businesses, process and record financial and operating data, communicate with our contractors and employees, analyze mining information, and estimate quantities of coal reserves, as well as other activities related to our businesses. We have implemented cyber security protocols and systems with the intent of maintaining the security of our operations and protecting our and our counterparties' confidential information against unauthorized access. Despite such efforts, we may be subject to cyber security breaches which could result in unauthorized access to our information systems or infrastructure.

Strategic targets, such as energy-related assets, may be at greater risk of future cyber attacks than other targets in the United States. Deliberate cyber attacks on, or security breaches in, our digital systems or information technology infrastructure, or that of third parties, could lead to corruption or loss of our proprietary data and potentially sensitive data, delays in production or delivery, difficulty in completing and settling transactions, challenges in maintaining our books and records, environmental damage, communication interruptions, other operational disruptions and third party liability. Our insurance may not protect us against such

occurrences. Consequently, it is possible that any of these occurrences, or a combination of them, could have a material adverse effect on our business, financial condition and results of operations. Further, as cyber incidents continue to evolve, we may be required to expend additional resources to continue to modify or enhance our protective measures or to investigate and remediate any vulnerability to cyber incidents.

We may not have sufficient cash from operations to enable us to pay the minimum quarterly distributions on our common and subordinated units.

The amount of cash we can distribute on our common and subordinated units principally depends upon the amount of cash we generate from our operations, which fluctuates from quarter to quarter based on, among other things:

In addition, the actual amount of cash we have available for distribution depends on several other factors, including:

We have a substantial amount of indebtedness, which may adversely affect our cash flow and our ability to operate our business.

At December 31, 2014, our total long-term indebtedness (excluding our sale-leaseback arrangements) was approximately $1.4 billion and we had available capacity of $174.0 million under our Revolving Credit Facility. Our substantial indebtedness could adversely affect our results of operations, business and financial condition, as well as our ability to pay distributions to our unitholders:

Restrictions in the agreements governing our indebtedness could limit our ability to make distributions to our unitholders.

The indenture governing our 2021 Senior Notes, our Senior Secured Credit Facilities and our longwall financing arrangements prohibit us from making distributions to unitholders if any default or event of default (as defined in each agreement) exists. In addition, the indenture governing our 2021 Senior Notes and our Senior Secured Credit Facilities contain covenants limiting our ability to pay distributions to unitholders. The covenants will apply differently depending on our fixed charge coverage ratio (as defined in the indenture for the 2021 Senior Notes and the Senior Secured Credit Facilities). If we do not exceed the fixed charge coverage ratio of 1.75 to 1.00 in respect of any quarter, we may be restricted in paying all or part of the minimum quarterly distribution to our unitholders.

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.

Foresight Reserves and a member of management own our general partner and Foresight Reserves controls our general partner, which has sole responsibility for conducting our business and managing our operations. Our general partner and its affiliates, including Foresight Reserves, could have conflicts of interest with us and limited duties, and they may favor their own interests to our detriment and that of our unitholders.

Foresight Reserves and a member of management own our general partner and Foresight Reserves controls our general partner and appoints all of the directors of our general partner. Although our general partner has a duty to manage us in a manner that it believes is not adverse to our interest, the executive officers and directors of our general partner have a fiduciary duty to manage our general partner in a manner beneficial to Foresight Reserves and a member of management. Therefore, conflicts of interest may arise between Foresight Reserves or its affiliates, including our general partner, on the one hand, or any of us and our unitholders, on the other hand. In resolving these conflicts of interest, our general partner may favor its own interests and the interests of its affiliates over the interests of our common unitholders. These conflicts include the following situations, among others:

In addition, Foresight Reserves and its affiliates currently hold substantial interests in other companies in the energy and natural resource sectors. We may compete directly with entities in which Foresight Reserves or its affiliates have an interest for acquisition opportunities and potentially will compete with these entities for new business or extensions of the existing services provided by us.

Our general partner intends to limit its liability regarding our obligations and under certain circumstances unitholders may have liability to repay distributions.

Our general partner intends to limit its liability under contractual arrangements between us and third parties so that the counterparties to such arrangements have recourse only against our assets, and not against our general partner or its assets. Our general partner may therefore cause us to incur indebtedness or other obligations that are nonrecourse to our general partner. Our partnership agreement provides that any action taken by our general partner to limit its liability is not a breach of our general partner’s duties, even if we could have obtained more favorable terms without the limitation on liability. In addition, we are obligated to reimburse or indemnify our general partner to the extent that it incurs obligations on our behalf. Any such reimbursement or indemnification payments would reduce the amount of cash otherwise available for distribution to our unitholders.

Unitholders may have to repay amounts wrongfully returned or distributed to them. Under Section 17-607 of the Delaware Revised Uniform Limited Partnership Act, or 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 are liable to the limited partnership for the distribution amount. 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.

The holder or holders of our incentive distribution rights may elect to cause us to issue common units to them in connection with a resetting of the target distribution levels related to the incentive distribution rights, without the approval of the conflicts committee of our general partner’s board of directors or the holders of our common units. This could result in lower distributions to holders of our common units.

Our general partner, the holder of our incentive distribution rights, has the right, at any time when there are no subordinated units outstanding and we have made cash distributions in excess of the then-applicable third target distribution for each of the prior four consecutive fiscal quarters, to reset the initial target distribution levels at higher levels based on our cash distribution levels at the time of the exercise of the reset election. Following a reset election by our general partner, the minimum quarterly distribution will be calculated as an amount equal to the prior cash distribution per common unit for the fiscal quarter immediately preceding the reset election (such amount is referred to as 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. The number of common units to be issued to our general partner will equal the number of common units that would have entitled the holder to an aggregate quarterly cash distribution for the quarter prior to the reset election equal to the distribution on the incentive distribution rights for the quarter 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 unit without such conversion. However, our general partner may transfer the incentive distribution rights at any time. It is possible that our general partner or a transferee could exercise this reset election at a time when we are experiencing declines in our aggregate cash distributions or at a time when the holders of the incentive distribution rights expect that we will experience declines in our aggregate cash distributions in the foreseeable future. In such situations, the holders of the incentive distribution rights may be experiencing, or may expect to experience, declines in the cash distributions it receives related to the incentive distribution rights and may therefore desire to be issued our common units rather than retain the right to receive incentive distributions 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 they would have otherwise received had we not issued new common units to the holders of the incentive distribution rights in connection with resetting the target distribution levels.

It is our policy to distribute a significant portion of our available cash to our unitholders, which could limit our ability to grow or make acquisitions.

Pursuant to our cash distribution policy, we distribute a significant portion of our available cash to our unitholders and rely primarily upon external financing sources, including commercial bank borrowings and the issuance of debt and equity securities, to fund potential acquisitions and expansion capital expenditures. As a result, to the extent we are unable to finance growth externally, our cash distribution policy may impair our ability to grow.

In addition, because we intend to distribute a significant portion of our available cash, our growth may not be as fast as that of businesses that reinvest their available cash to expand ongoing operations. To the extent we issue additional units in connection with any acquisitions or expansion capital expenditures, the payment of distributions on those additional units may increase the risk that we will be unable to maintain or increase our per unit distribution level. There are no limitations in our partnership agreement on our ability to issue additional units, including units ranking senior to the common units. The incurrence of additional commercial borrowings or other debt to finance our growth strategy would result in increased interest expense, which, in turn, may impact the available cash that we have to distribute to our unitholders.

We may issue additional units without unitholder approval which would dilute existing unitholder ownership interests.

In accordance with Delaware law and the provisions of our partnership agreement, we may issue additional partnership interests that are senior to the common units in right of distribution, liquidation and voting. Additionally, we are not limited in the number of additional limited partner interests that we may issue at any time without the approval of our unitholders. The issuance of additional common units would have the following effects:

In addition, to the extent that we are unable to generate a sufficiently large return from investment of the proceeds of the issuance of additional units, such issuances would be dilutive to the existing unitholders.

Our partnership agreement replaces our general partner’s fiduciary duties to holders of our units.

Our partnership agreement contains provisions that eliminate and replace the fiduciary standards to which our general partner would otherwise be held by state fiduciary duty law with several different contractual standards. For example, our partnership agreement permits our general partner to make a number of decisions in its individual capacity, as opposed to in its capacity as our general partner, or otherwise free of fiduciary duties to us and our unitholders. This entitles our general partner to consider only the interests and factors that it desires and relieves it of any duty or obligation to give any consideration to any interest of, or factors affecting, us, our affiliates or our limited partners. Examples of decisions that our general partner may make in its individual capacity include:

By purchasing a common unit, a unitholder is treated as having consented to the provisions in the partnership agreement, including the provisions discussed above.

Our partnership agreement restricts the remedies available to holders of our units for actions taken by our general partner that might otherwise constitute breaches of fiduciary duty.

Our partnership agreement provides that our general partner is restricted from engaging in any business activities other than acting as our general partner and those activities incidental to its ownership interest in us. Foresight Reserves, as parent of our general partner, and the other affiliates of our general partner are not prohibited from engaging in other businesses or activities, including those that might be in direct competition with us. Our partnership agreement contains provisions that restrict the remedies available to unitholders for actions taken by our general partner that might otherwise constitute breaches of fiduciary duty under state fiduciary duty law. For example, our partnership agreement provides that:

In connection with a situation involving a transaction with an affiliate or a conflict of interest, other than one where our general partner is permitted to act in its sole discretion, any determination by our general partner must be made in good faith. If an affiliate transaction or the resolution of a conflict of interest is not approved by our common unitholders or the conflicts committee then it will be presumed that, in making its decision, taking any action or failing to act, the board of directors acted in good faith, and in any proceeding brought by or on behalf of any limited partner or the partnership, the person bringing or prosecuting such proceeding will have the burden of overcoming such presumption.

Our partnership agreement provides that the conflicts committee of the board of directors of our general partner may be comprised of one or more independent directors. If our general partner establishes a conflicts committee with only one independent director, your interests may not be as well served as if the conflicts committee were comprised of at least two independent directors. A single-member conflicts committee would not have the benefit of discussion with, and input from, other independent directors.

The Cline Group currently holds substantial interests in other companies in the coal mining business, including other coal reserves in Illinois. For example, The Cline Group makes investments and purchases entities that acquire, own and operate coal mining businesses and transportation. These investments and acquisitions may include entities or assets that we would have been interested in acquiring. Therefore, The Cline Group and certain other affiliates of our general partner may compete with us for investment opportunities and affiliates of our general partner may own an interest in entities that compete with 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 Foresight Reserves. 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 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 for us and our unitholders.

Holders of our common units have limited voting rights and are not entitled to elect or remove our general partner or its directors, which could reduce the price at which the common units would trade.

Compared to the holders of common stock in a corporation, unitholders have limited voting rights and, therefore, limited ability to influence management’s decisions regarding our business. Unitholders have no right on an annual or ongoing basis to elect our general partner or its board of directors. The board of directors of our general partner, including the independent directors, is chosen entirely by Foresight Reserves, as a result of it owning our general partner, and not by our unitholders. Unlike publicly traded corporations, we do not conduct annual meetings of our unitholders to elect directors or conduct other matters routinely conducted at annual meetings of stockholders of corporations. As a result of these limitations, the price at which the common units trade could be diminished because of the absence or reduction of a takeover premium in the trading price.

If our unitholders are dissatisfied with the performance of our general partner, they have limited ability to remove our general partner. Unitholders are unable to remove our general partner without its consent because our general partner and its affiliates own sufficient units to be able to prevent its removal. In addition, any vote to remove our general partner during the subordination period must provide for the election of a successor general partner by the holders of a majority of the common units and a majority of the subordinated units, voting as separate classes. Foresight Reserves has the ability to prevent the removal of our general partner.

Our general partner interest or 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 to a third party without the consent of our unitholders. Furthermore, our partnership agreement does not restrict the ability of the owners of our general partner to transfer their membership interests in our general partner to a third party. The new owners 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 designees and thereby exert significant control over the decisions taken by the board of directors and executive officers of our general partner. This effectively permits a “change of control” without the vote or consent of the unitholders.

The incentive distribution rights may be transferred to a third party without unitholder consent.

Our general partner or our sponsor may transfer the incentive distribution rights to a third party at any time without the consent of our unitholders. If our sponsor transfers the incentive distribution rights to a third party but retains its ownership interest in our general partner, 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 our sponsor had retained ownership of the incentive distribution rights. For example, a transfer of incentive distribution rights by our sponsor could reduce the likelihood of our sponsor accepting offers made by us relating to assets owned by it, as it would have less of an economic incentive to grow our business, which in turn would impact our ability to grow our asset base.

Our general partner has a call right that may require unitholders to sell their common units at an undesirable time or price.

If at any time our general partner and its affiliates own more than 80% of the common units, our general partner has the right, which it may assign to any of its affiliates or to us, but not the obligation, to acquire all, but not less than all, of the common units held by unaffiliated persons at a price equal to the greater of (1) the average of the daily closing price of the common units over the 20 trading days preceding the date three days before notice of exercise of the call right is first mailed and (2) the highest per-unit price paid by our general partner or any of its affiliates for common units during the 90-day period preceding the date such notice is first mailed. As a result, unitholders may be required to sell their common units at an undesirable time or price and may not receive any return or a negative return on their investment. Unitholders may also incur a tax liability upon a sale of their 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 causing us to issue additional common units and exercising its call right. If our general partner exercised its limited call right, the effect would be to take us private and, if the units were subsequently deregistered, we would no longer be subject to the reporting requirements of the Securities Exchange Act of 1934 (the “Exchange Act”). As of February 27, 2015, Foresight Reserves, Chris Cline and a member of management own an aggregate of 73.2% and 100.0%, of our common and subordinated units, respectively. At the end of the subordination period, assuming no additional issuances of units (other than upon the conversion of the subordinated units), Foresight Reserves and a member of management would own an aggregate of 86.6% of our common units.

Our partnership agreement restricts the voting rights of unitholders owning 20% or more of our common units.

Our partnership agreement restricts unitholders’ voting rights by providing that any units held by a person or group that owns 20% or more of any class of units then outstanding, other than our general partner and its affiliates, their transferees and persons who acquired such units with the prior approval of the board of directors of our general partner, cannot vote on any matter.

Cost reimbursements due to our general partner and its affiliates for services provided to us or on our behalf reduce cash available for distribution to our unitholders. Our general partner determines the amount and timing of such reimbursements.

We are obligated under our partnership agreement to reimburse our general partner and its affiliates for all expenses they incur and payments they make on our behalf. Our partnership agreement does not limit the amount of expenses for which our general partner and its affiliates may be reimbursed. These expenses include salary, bonus, incentive compensation and other amounts paid to persons who perform services for us or on our behalf and expenses allocated to our general partner by its affiliates. Our partnership agreement provides that our general partner determines the expenses that are allocable to us. The reimbursement of expenses and payment of fees, if any, to our general partner and its affiliates reduces the amount of cash available for distributions to our unitholders.

We will be required by Section 404 of the Sarbanes-Oxley Act to evaluate the effectiveness of our internal controls. If we are unable to achieve and maintain effective internal controls, our operating results and financial condition could be harmed.

We will be required to comply with Section 404 of the Sarbanes-Oxley Act beginning with the year ending December 31, 2015. Section 404 will require that we evaluate our internal control over financial reporting to enable management to report on the effectiveness of those controls. Management is responsible for establishing and maintaining adequate internal control over financial reporting. Our internal control over financial reporting is a process designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of our consolidated financial statements in accordance with U.S. generally accepted accounting principles (“U.S. GAAP”). We have begun the lengthy process of evaluating our internal controls. We cannot predict the outcome of our review at this time. During the course of the review, we may identify control deficiencies of varying degrees of severity.

As a publicly traded partnership, we will be required to report control deficiencies that constitute a material weakness in our internal control over financial reporting. If we fail to implement the requirements of Section 404 in a timely manner, if we are unable to conclude that our internal control over financial reporting is effective or if we fail to comply with our financial reporting requirements, investors may lose confidence in the accuracy and completeness of our financial reports. In addition, we or members of our management could be the subject of adverse publicity; investigations and sanctions by regulatory authorities, including the Securities and Exchange Commission (“SEC”) and the NYSE; and unitholder lawsuits. Failure to comply would also result in higher fees for audit and remediation services, which could be significant. Any of the above consequences could impose significant unanticipated costs on us.

As a new publicly traded partnership, we are not required to attest to the effectiveness of our internal control over financial reporting pursuant to Section 404 of the Sarbanes-Oxley Act of 2002 until December 31, 2015.

We are not required to have our independent registered public accounting firm attest to the effectiveness of our internal controls until December 31, 2015. Accordingly, we will not have our independent registered public accounting firm attest to the effectiveness of our internal controls until our fiscal year ending December 31, 2015. Once we are required to do so, and even if we conclude that our internal control over financial reporting is effective, our independent registered public accounting firm may issue a report that is adverse in the event it is not satisfied with the level at which our controls are documented, designed, operated or reviewed, or if it interprets the relevant requirements differently from us.

The NYSE does not require a publicly traded partnership like us to comply with certain of its corporate governance requirements.

Our common units are listed on the NYSE. Because we are a publicly traded partnership, the NYSE does not require us to have a majority of independent directors on our general partner’s board of directors or to establish a compensation committee or a nominating and corporate governance committee. Accordingly, unitholders do not have the same protections afforded to certain corporations that are subject to all of the NYSE corporate governance requirements.

Our tax treatment depends on our status as a partnership for federal income tax purposes, as well as our not being subject to a material amount of entity-level taxation by individual states. If the Internal Revenue Service (“IRS”) were to treat us as a corporation for federal income tax purposes or we were to become subject to material additional amounts of entity-level taxation for state tax purposes, then our cash available for distribution to you could be substantially reduced.

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. Despite the fact that we are organized as 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 so treated, a change in our business, a change in current law or a change in the interpretation of 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 be liable for state income tax at varying rates. Distributions to you would generally be taxed again as corporate distributions, and no income, gains, losses, deductions or credits would flow through to you. Because a tax would be imposed upon us as a corporation, our cash available for distribution to you would be substantially reduced. Therefore, treatment of us as a corporation would result in a material reduction in the anticipated cash flow and after-tax return to the unitholders, likely causing a substantial reduction in the value of our common units.

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 may be adjusted to reflect the impact of that law on us. Several states have been evaluating ways to subject partnerships to entity-level taxation through the imposition of state income, franchise or other forms of taxation. If any state were to impose a tax upon us as an entity, the cash available for distribution to you would be reduced and the value of our common units could be negatively impacted.

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 changes or differing interpretations at any time. For example, the Obama administration’s budget proposal for fiscal year 2016 recommends that certain publicly traded partnerships earning income from activities related to fossil fuels be taxed as corporations beginning in 2021. From time to time, members of Congress propose and consider substantive changes to the existing federal income tax laws that affect publicly traded partnerships. If successful, the Obama administration’s proposal or other similar proposals could eliminate the qualifying income exception to the treatment of all publicly-traded partnerships as corporations upon which we rely for our treatment as a partnership for U.S. federal income tax purposes.

Any modification to the federal income tax laws may be applied retroactively and could make it more difficult or impossible for us to meet the exception for certain publicly traded partnerships to be treated as partnerships for federal income tax purposes. We are unable to predict whether any of these changes or other proposals will ultimately be enacted. Any such changes could negatively impact the value of an investment in our common units.

You will be required to pay taxes on your share of our income even if you do not receive any cash distributions from us.

You will be required to pay federal income taxes and, in some cases, state and local income taxes on your share of our taxable income regardless of whether you receive cash distributions from us. You may not receive cash distributions from us equal to your share of our taxable income or even equal to the actual tax liability resulting from that income.

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 no longer be 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. Foresight Reserves owns, directly and indirectly, more than 50% of the total interests in our capital and profits. Therefore, a transfer by Foresight Reserves of all or a portion of its interests in us could result in a termination of us as a partnership for federal income tax purposes. Our termination would, among other things, result in the closing of our taxable year for all unitholders and could result in a deferral of depreciation deductions allowable in

computing our taxable income. In the case of a unitholder reporting on a taxable year other than the calendar year, the closing of our taxable year may also result in more than twelve months of our taxable income or loss being includable in his taxable income for the year of termination. Our termination currently 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 federal income 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.

Tax gain or loss on the disposition of our common units could be more or less than expected.

If you sell your common units, you will recognize a gain or loss equal to the difference between the amount realized and your tax basis in those common units. Because distributions in excess of your allocable share of our net taxable income result in a decrease in your tax basis in your common units, the amount, if any, of such prior excess distributions with respect to the units you sell will, in effect, become taxable income to you if you sell such units at a price greater than your tax basis in those units, even if the price you receive is less than your 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 of depreciation and amortization deductions and certain other items. In addition, because the amount realized includes a unitholder’s share of our nonrecourse liabilities, if you sell your units, you may incur a tax liability in excess of the amount of cash you receive 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.

Investments in common units by tax-exempt entities, such as employee benefit plans and individual retirement accounts (“IRAs”), and non-U.S. persons raise 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 and will 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 U.S. federal income tax returns and pay tax on their shares of our taxable income. If you are a tax-exempt entity or a non-U.S. person, you should consult your tax advisor before investing in our common units.

If the IRS contests the federal income tax positions we take, the market for our common units may be adversely impacted and the cost of any IRS contest may reduce our cash available for distribution to you.

We have not requested a ruling from the IRS regarding our treatment as a partnership for federal income tax purposes. The IRS could adopt positions that differ from the positions we take. 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 by the IRS, and the outcome of such contest, may materially and adversely impact the market for our common units and the price at which they trade. The costs of any such contest would result in a reduction in cash available for distribution to our unitholders and would indirectly be borne by our unitholders.

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 the common units.

Because we cannot match transferors and transferees of common units, we adopt 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 you. It also could affect the timing of these tax benefits or the amount of gain from your sale of common units and could have a negative impact on the value of our common units or result in audit adjustments to your 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 our unitholders.

We generally prorate items of income, gain, loss and deduction between transferors and transferees of our common units each month based upon the ownership of our common units on the first day of each month, rather than on the basis of the date a particular common unit is transferred. Nonetheless, we will allocate certain deductions for depreciation of capital additions based upon the date the underlying property is placed in service. The use of this proration method may not be permitted under existing Treasury Regulations, and although the U.S. Treasury Department issued proposed Treasury Regulations allowing a similar monthly simplifying convention, such regulations are not final and do not specifically authorize the use of the proration method we have adopted. If the IRS was 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.

We have adopted certain valuation methodologies in determining unitholder’s allocations of income, gain, loss and deduction. The IRS may challenge these methods or the resulting allocations, and such a challenge could adversely affect the value of our common units.

In determining the items of income, gain, loss and deduction allocable to our unitholders, we must routinely determine the fair market value of our respective assets. Although we may from time to time consult with professional appraisers regarding valuation matters, we make many fair market value estimates using a methodology based on the market value of our common units as a means to measure the fair market value of our respective assets. The IRS may challenge these valuation methods and the resulting allocations of income, gain, loss and deduction.

A successful IRS challenge to these methods or allocations could adversely affect the amount, character, and timing 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.

A unitholder whose common units are the subject of a securities loan (e.g., a loan 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 common units during the period of the loan and may recognize gain or loss from the disposition.

Because there are no specific rules governing the federal income tax consequences of loaning a partnership interest, a unitholder whose common units are the subject of a securities loan may be considered as having disposed of the loaned units. In that case, the unitholder may no longer be treated for federal income 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, 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 consult a tax advisor to discuss whether it is advisable to modify any applicable brokerage account agreements to prohibit their brokers from borrowing their common units.

Certain U.S. federal income tax preferences currently available with respect to coal exploration and development may be eliminated as a result of future legislation.

President Obama’s Proposed Fiscal Year 2016 budget (the “Budget Proposal”) recommends elimination of certain key U.S. federal income tax preferences related to coal exploration and development. The Budget Proposal would (1) repeal expensing of exploration and development costs relating to coal, (2) repeal the percentage depletion allowance with respect to coal properties, (3) repeal capital gains treatment of coal royalties, and (4) repeal the domestic manufacturing deduction for the production of coal. The passage of any legislation as a result of the Budget Proposal or any other similar changes in U.S. federal income tax laws could eliminate or defer certain tax deductions that are currently available with respect to coal exploration and development, and any such change could increase the taxable income allocable to our unitholders and negatively impact the value of an investment in our units.

You will likely be subject to state and local taxes and return filing requirements in states where you do not live as a result of investing in our common units.

In addition to federal income taxes, you will likely 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 conduct business or own property now or in the future, even if you do not live in any of those jurisdictions. We own assets and conduct business in several states (including Illinois and Missouri and, through our affiliates, in Indiana and Louisiana), each of which currently imposes a personal income tax and also imposes income taxes on corporations and other entities. You will likely be required to file state and local income tax returns and pay state and local income taxes in these states. Further, you may be subject to penalties for failure to comply with these requirements. As we make acquisitions or expand our business, we may own assets or conduct business in additional states or foreign jurisdictions that impose a personal income tax. It is your responsibility to file all U.S. federal, foreign, state and local tax returns.

We believe that we have sufficient reserves to replace capacity from depleting mines for the foreseeable future and that our current reserve base is one of our strengths. We estimate that we controlled over 3 billion tons, principally through lease, of proven and probable recoverable reserves at December 31, 2014. Our coal reserve estimate is based on a study prepared by a third-party mining and geological consultant using data obtained from our drilling activities and other available geologic data. Our coal reserve estimates are periodically updated to reflect past coal production and other geologic and mining data. Acquisitions or sales of coal properties will also change these estimates. Changes in mining methods or the utilization of new technologies may increase or decrease the recovery basis for a coal seam.

Our coal reserve estimates include reserves that can be economically and legally extracted or produced at the time of their determination. In determining whether our reserves meet this standard, we take into account, among other things, the possible necessity of revising a mining plan, changes in estimated future costs, changes in future cash flows caused by changes in costs required to be incurred to meet regulatory requirements and obtaining mining permits, variations in quantity and quality of coal, and varying levels of demand and their effects on selling prices. Further, the economics of our reserves are based on market conditions including contracted pricing, market pricing and overall demand for our coal. Thus, the actual value at which we no longer consider our reserves to be economic varies depending on the length of time in which the specific market conditions are expected to last. We consider our reserves to be economic at a price in excess of our cash costs to mine the coal and our ongoing replacement capital. See Item 1A. “Risk Factors—Risks Related to Our Business—We face numerous uncertainties in estimating our economically recoverable coal reserves.”

Certain of our mines are subject to private coal leases. Private coal leases normally have a stated term and usually give us the right to renew the lease for a stated period or to maintain the lease in force until the exhaustion of mineable and merchantable coal contained on the relevant site. These private leases provide for royalties to be paid to the lessor either as a fixed amount per ton or as a percentage of the sales price. Many leases also require payment of a minimum royalty, payable either at the time of execution of the lease or in periodic installments.

All of our recoverable coal reserves are assigned reserves as of December 31, 2014. All of our reserves are considered high sulfur coal, with average sulfur content ranging between 1.71% and 3.33% and high Btu coal, with Btu content ranging between 10,591 and 11,893 Btu per pound. The table below presents our estimated recoverable coal reserves at December 31, 2014.

		Average Seam				In-Place		Clean Recoverable Tons (2)						Theoretical Coal Quality
		Thickness		Area		Tons (1)		(in 000's)						(As Received Basis)
Property Control	Seam	(Feet)		(Acres)		(in 000's)		Proven		Probable		Total		Sulfur %		Btu/lb

Williamson Energy, LLC (3)	6	5.81			28,810		317,736		132,326		54,537		186,863		2.20		11,893
Williamson Energy, LLC (3)	5	4.24			39,070		308,215		111,507		85,437		196,944	1.71			11,799
Sugar Camp Energy, LLC	6		6.40		103,454		1,248,270		364,916		394,231		759,147	2.46			11,820
Sugar Camp Energy, LLC	5	4.75			104,303		925,724		238,407		362,134		600,541	2.44			11,712
Hillsboro Energy LLC	6	7.33			100,182		1,409,550		278,805		591,778		870,583	3.33			10,960
Macoupin Energy LLC	6	7.19			68,838		941,141		269,674		187,462		457,136	2.62			10,591
Total Foresight Energy LP							5,150,636		1,395,635		1,675,579		3,071,214

Each of the mining companies leases the reserves they mine pursuant to a series of leases with related entities under common ownership, Natural Resources Partners, LP (“NRP”) and its subsidiaries, and other independent third parties in the normal course of business. The mineral reserve leases can generally be renewed as long as the mineral reserves are being developed and mined until all economically recoverable reserves are depleted or until mining operations cease. The leases require a production royalty at the greater amount of a base amount per ton or a percent of the gross selling price of the coal. Generally, the leases contain provisions that require

the payment of minimum royalties regardless of the volume of coal produced or the level of mining activity. The minimum royalties are generally recoupable against production royalties over a contractually defined period of time (generally five to ten years). Some of these agreements also require overriding royalty and/or wheelage payments. Under the terms of some mineral reserve mining leases, we are to use commercially reasonable efforts to acquire additional mineral reserves in certain properties as defined in the agreements and are responsible for the acquisition costs and the assets are to be titled to the lessor.

See Item 13. “Certain Relationships and Related-Party Transactions and Director Independence” for a summary of key terms of mineral reserve leases with affiliated parties.

See Item 8. “Financial Statements and Supplementary Data,” Note 21, “Contingencies” in the notes to our consolidated financial statements in this Annual Report on Form 10-K for a description of certain of our pending legal proceedings, which are incorporated herein by reference. We are also party to various other litigation matters, in most cases involving ordinary and routine claims incidental to our business. We cannot reasonably estimate the ultimate legal and financial liability with respect to all pending litigation matters. However, we believe, based on our examination of such matters, that the ultimate liability will not have a material adverse effect on our financial position, results of operation or cash flows. As of December 31, 2014, we have $1.2 million accrued, in the aggregate, for various litigation matters.

Information concerning mine safety violations or other regulatory matters required by Section 1503(a) of the Dodd-Frank Wall Street Reform and Consumer Protection Act (“Dodd-Frank Act”) and Item 104 of Regulation S-K (17 CFR 229.104) is included in Exhibit 95.1 to this Annual Report on Form 10-K for the year ended December 31, 2014.

Item 5. Market for Registrant’s Common Equity, Related Unitholder Matters and Issuer Purchases of Equity Securities

The common units representing limited partnership’ interests are listed and began trading on the New York Stock Exchange (“NYSE”) under the symbol “FELP” on June 18, 2014. On February 27, 2015, the closing market price for FELP common units was $16.85 per unit and there were 65,059,477 common units outstanding and 64,954,691 subordinated units outstanding. There were approximately 2,294 record holders of our common units as of December 31, 2014.

The following table sets forth the range of high and low sales prices per common unit and the amount of cash distributions declared and paid with respect to each unit, from the June 18, 2014 initial listing date of our common units to December 31, 2014.

All subordinated units are currently held by Foresight Reserves and a member of management. The principal difference between our common units and subordinated units is that subordinated unitholders are not entitled to receive a distribution of available cash until the holders of common units have received the minimum quarterly distribution (“MQD”). The MQD is $0.3375 per unit for such quarter plus any cumulative arrearages of previously unpaid MQDs from previous quarters. Also, subordinated unitholders are not entitled to receive arrearages. The subordination period will end, and the subordinated units will convert to common units, on a one-for-one basis, on the first business day after the Partnership has paid the MQD for each of three consecutive, non-overlapping four-quarter periods ending on or after March 31, 2017 and there are no outstanding arrearages on the common units. Notwithstanding the foregoing, the subordination period will end on the first business day after the Partnership has paid an aggregate amount of at least $2.025 per unit (150.0% of the MQD on an annualized basis) on the outstanding common and subordinated units and the Partnership has paid the related distribution on the incentive distribution rights, for any four-quarter period ending on or after March 31, 2015 and there are no outstanding arrearages on the common units.

Our partnership agreement provides that our general partner will make a determination as to whether a distribution will be made, but our partnership agreement does not require us to pay distributions at any time or at any amount. Our partnership agreement authorizes us to issue an unlimited number of additional partnership interests for the consideration and on the terms and conditions determined by our general partner without the approval of the unitholders.

We intend to make cash distributions to unitholders on a quarterly basis equal to at least the MQD. However, there is no assurance as to the future cash distributions since they are dependent upon future earnings, cash flows, capital requirements, financial condition and other factors. Additionally, under our Revolving Credit Facility and 2021 Senior Notes, we will not be able to pay distributions to unitholders in any such quarter in the event there exists a borrowing base deficiency or an event of default either before or after giving effect to such distribution or we are not in pro forma compliance with our Revolving Credit Facility after giving effect to such distribution.

Our general partner owns all of the incentive distribution rights (“IDRs”). IDRs represent the right to receive an increasing percentage of quarterly distributions of available cash from operating surplus after the MQD and the target distribution levels (described below) have been achieved. Our general partner may transfer these rights separately from its general partner interest, subject to restrictions in our partnership agreement. Our general partner, as the IDR holder, will have the right, subsequent to the subordination period and subject to distributions exceeding the MQD by at least 150% for four consecutive quarters, to reset the target distribution levels and receive common units.

The following table illustrates the percentage allocation of available cash from operating surplus between the unitholders and our general partner (as the holder of our IDRs) based on the specified target distribution levels. The amounts set forth under the column heading “Marginal Percentage Interest in Distributions” are the percentage interests of the IDR holder and the unitholders of any available cash from operating surplus we distribute up to and including the corresponding amount in the column “Total Quarterly Distribution Per Common Unit”. The percentage interests shown for our unitholders and our general partner for the MQD are also applicable to quarterly distribution amounts that are less than the MQD.

The percentage interests set forth below assumes there are no arrearages on common units.

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

On June 23, 2014, the Partnership sold 17.5 million common units in an initial public offering at a price of $20.00 per unit pursuant to a Registration Statement on Form S-1 (Registration No. 333-179304), which was declared effective by the Securities and Exchange Commission on June 17, 2014. The Partnership received $329.9 million of proceeds from the sale of common units, net of underwriters’ discount of $20.1 million, which were used to repay $210.0 million of principal on the term loan and to pay a $115.0 million special distribution to Foresight Reserves and a member of management, on a pro rata basis. The remaining proceeds were used to pay other offering costs.

The following tables set forth the selected historical consolidated financial data of the Partnership for each of the last five years and should be read in conjunction with the consolidated financial statements and notes thereto included elsewhere in this Annual Report on Form 10-K.

	For the Year Ended December 31,
	2014			2013			2012			2011			2010
	(In Thousands, Except per Unit Data)
Coal sales	$	1,109,404		$	957,412		$	845,886		$	500,791		$	362,592
Costs and expenses:
Cost of coal produced (excluding depreciation, depletion and amortization)		449,905			360,861			303,638			174,183			130,610
Cost of coal purchased		18,232			2,163			6,163			—			—
Transportation		226,029			197,839			171,679			98,394			58,482
Depreciation, depletion and amortization		167,039			161,216			124,552			70,411			55,647
Accretion on asset retirement obligations		1,621			1,527			1,368			1,705			2,011
Impairment of prepaid royalties		34,700			—			—			—			—
Selling, general and administrative		33,679			32,291			41,528			38,894			28,367
Gain on coal derivatives		(76,330	)		(2,392	)		(534	)		(2,395	)		—
Other operating income, net (1)		(2,527	)		(280	)		(10,759	)		(791	)		(2,611	)
Operating income		257,056			204,187			208,251			120,390			90,086
Other expenses:
Loss on early extinguishment of debt		4,979			77,773			—			—			—
Interest expense, net		113,030			115,897			82,580			38,193			40,431
Net income from continuing operations		139,047			10,517			125,671			82,197			49,655
Net loss from discontinued operations		—			—			—			—			(40,893	)
Net income		139,047			10,517			125,671			82,197			8,762
Less: net income (loss) attributable to noncontrolling interests		3,847			2,236			(160	)		104			909
Net income attributable to controlling interests		135,200		$	8,281		$	125,831		$	82,093		$	7,853
Less: predecessor net income attributable to controlling interests prior to initial public offering		65,008
Net income subsequent to initial public offering attributable to limited partner units	$	70,192

Per Unit Data
Net income subsequent to initial public offering per limited partner unit - basic and diluted	$	0.54		n/a			n/a			n/a			n/a
Distributions declared per limited partner unit	$	0.38		n/a			n/a			n/a			n/a
Statements of Cash Flows
Net cash provided by operating activities	$	236,040		$	179,526		$	209,691		$	103,143		$	61,388
Net cash used in investing activities	$	(224,109	)	$	(209,275	)	$	(207,039	)	$	(332,821	)	$	(272,117	)
Net cash (used in) provided by financing activities	$	(9,809	)	$	25,145		$	(26,525	)	$	247,988		$	196,091
Balance Sheet Data (at period end)
Cash and cash equivalents	$	25,406		$	23,284		$	27,888		$	51,761		$	33,451
Property, plant, equipment and development, net	$	1,473,063		$	1,414,074		$	1,401,285		$	1,323,800		$	995,425
Total assets	$	1,865,222		$	1,710,171		$	1,695,288		$	1,546,969		$	1,131,880
Total long-term debt and capital lease obligations (2)	$	1,360,671		$	1,519,213		$	1,061,949		$	897,411		$	605,390
Total partners’ capital (deficit)	$	135,683		$	(148,116	)	$	280,103		$	394,205		$	282,066
Other Data
Adjusted EBITDA (3)	$	404,467		$	362,241		$	338,429		$	192,402		$	146,835
Tons produced (4)		22,547			17,991			15,080			9,028			6,813
Tons sold(4)		22,044			18,589			14,403			8,773			6,730
Coal sales realization per ton sold (5)	$	50.33		$	51.50		$	58.73		$	57.08		$	53.88
Cash costs per ton sold(6)	$	20.80		$	19.46		$	21.20		$	19.85		$	19.41

	For the Year Ended December 31,
	2014			2013			2012			2011		2010
	(In Thousands)
Net income from continuing operations attributable to controlling interests	$	135,200		$	8,281		$	125,831		$	82,093	$	48,746
Interest expense, net		113,030			115,897			82,580			38,193		40,431
Depreciation, depletion and amortization		167,039			161,216			124,552			70,411		55,647
Accretion on asset retirement obligations		1,621			1,527			1,368			1,705		2,011
Impairment of prepaid royalties		34,700			—			—			—		—
Equity-based compensation		5,024			—			4,632			—		—
Unrealized gain on coal derivatives		(57,126	)		(2,453	)		(534	)		—		—
Loss on early extinguishment of debt		4,979			77,773			—			—		—
Adjusted EBITDA	$	404,467		$	362,241		$	338,429		$	192,402	$	146,835

Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations

You should read the following discussion and analysis together with Item 6.— “Selected Financial Data” and our consolidated financial statements and related notes included elsewhere in this Annual Report on Form 10-K. This discussion contains forward-looking statements about our business, operations and industry that involve risks and uncertainties, such as statements regarding our plans, objectives, expectations and intentions. Our future results and financial condition may differ materially from those we currently anticipate as a result of the factors we describe under “Cautionary Statement Regarding Forward-Looking Statements,” Item 1A.“Risk Factors” and elsewhere in this Annual Report on Form 10-K. All references to produced tons, sold tons, or cash cost per ton sold refer to clean tons of coal.

Foresight Energy LLC (“FELLC”), a Delaware limited liability company, was formed in September 2006 for the development, mining, transportation and sale of coal mined. Prior to June 23, 2014, Foresight Reserves, L.P. (“Foresight Reserves”) owned 99.333% of FELLC and a member of management owned 0.667%. The Cline Group, Foresight Reserves’ controlling member, has well-established experience in the development and operation of coal mining facilities. Over the last 30 years, The Cline Group has acquired, permitted, developed or operated over 25 separate coal mining operations in Appalachia and the Illinois Basin.

Foresight Energy LP (“FELP”), a Delaware limited partnership, and Foresight Energy GP LLC (“FEGP” or “general partner”), a Delaware limited liability company, were formed in January 2012. FELP was formed to own FELLC and FEGP was formed to be the general partner of FELP. Prior to June 23, 2014, FELP had no operating or cash flow activity and no recorded net assets. On June 23, 2014, in connection with the initial public offering (“IPO”) of FELP, Foresight Reserves and a member of management contributed their ownership interests in FELLC to FELP for which they were issued common units and subordinated units in FELP. FELP issued 17,500,000 common units to the public at $20.00 per unit, representing a 13.5% limited partnership interest.

The presented financial results include the combined financial position, results of operations and cash flow information of Foresight Energy LP and Foresight Energy LLC and its subsidiaries for all periods presented. In this Item 7, all references to “FELP,” the “Partnership,” “we,” “us,” and “our” refer to the combined results of Foresight Energy LP and Foresight Energy LLC and its subsidiaries, unless the context otherwise requires or where otherwise indicated.

We control over 3 billion tons of coal reserves, almost all of which exist in three large, contiguous blocks of coal: two in central Illinois and one in southern Illinois. Since our inception, we have invested significantly in capital expenditures to develop what we believe are industry-leading, geologically similar, low -cost and highly productive mines and related infrastructure. We currently operate under one reportable segment with four underground mining complexes in the Illinois Basin: Williamson, Sugar Camp and Hillsboro, all three of which are longwall operations, and Macoupin, which is currently a continuous miner operation. The Williamson and Hillsboro complexes are each operating with one longwall system and Sugar Camp is operating with two longwall mining systems, the second of which emerged from development on June 1, 2014. The timing of additional development is dependent on several factors, including permitting, access to capital, market demand, equipment availability and the committed sales position at our existing mining operations.

Our coal is sold to a diverse customer base, including electric utility and industrial companies in the eastern United States and overseas. We generally sell a majority of our coal to customers at delivery points other than our mines, including, but not limited to, river terminals on the Ohio and Mississippi Rivers and at two ports in New Orleans. As such, we generally bear the transportation cost and risk to and through these facilities and we therefore do not report coal sales and transportation revenue separately in our consolidated statements of operations.

Coal Sales. Our sales strategy is generally to enter into long-term contracts for the majority of our production to mitigate price fluctuations. Our average coal sales realization per ton in the near-term may decrease as we replace expiring favorably priced supply contracts with new supply contracts at contractually negotiated market prices. In recent years, domestic coal prices have weakened due to reduced demand from coal-fired plants and international prices have also declined significantly as a result of excess supply in the marketplace. We expect this low-price environment to continue into 2015 but we anticipate the lower coal prices will be somewhat offset by lower transportation costs due to an increased mix of domestic sales.

Demand for coal can increase due to unusually hot or cold weather as consumers use more electricity to air condition or heat their homes. Conversely, mild weather can result in softer demand for our coal. Adverse weather conditions, such as blizzard or flood, can affect our ability to mine and ship our coal and our customers’ ability to take delivery of coal.

Cost of Coal Sales (Excluding Depreciation, Depletion and Amortization). Our cost of coal sales (excluding depreciation, depletion and amortization) includes, but is not limited to, labor and benefits, supplies, repairs, utilities, insurance, equipment rental, mine lease costs (royalties), property and subsidence costs, production taxes, belting, coal preparation and direct mine overhead. Each of these cost components has its own drivers, which can include the cost and availability of labor, changes in health care and insurance regulations and costs, the cost of consumable items or inputs in to our supplies, changes in regulations impacting our industry, and/or our staffing levels. In addition, geology can unfavorably impact our costs by requiring incremental roof control support and higher water handling and equipment maintenance expenses. Certain of our royalties are dependent directly upon the price at which we sell our coal and our cost to transport the coal to the customers, in addition to having minimum payment requirements. Also, effective July 1, 2014, we terminated our guaranteed cost workers’ compensation insurance program in favor of a high deductible insurance program. Thus far we have not experienced claims unfavorable to our prior cost of insurance.

Regulatory Environment. A variety of actions taken by regulatory agencies, including, but not limited to, climate change regulation, challenges to the issuance or renewal of our permits to operate and regulations governing the operations of our mines, could substantially increase compliance costs for us and our customers, reduce general demand for coal, or interrupt operations at one or more of our mining complexes.

Transportation. We generally sell our coal to customers at three distinct delivery points; either at our mines, at river terminals on the Ohio and Mississippi Rivers, or at two export terminals in New Orleans. Except for those sales that occur at our mine, we generally bear the cost of transportation. Because we are responsible for the cost of transporting our coal to these various delivery points, we also bear the risk that our transportation expense will increase over time. Where possible, we enter into long-term transportation and throughput agreements to secure capacity and price certainty. These agreements generally require minimum annual throughput volumes. Failure to meet the minimum annual volume requirements can result in higher transportation costs to us on a per ton basis. Our transportation costs also correlate to the distance required to transport our coal to the buyers. As a result, the transport of our coal to domestic buyers has lower associated costs than the transport of our coal to international buyers. International sales incur higher transportation costs because the delivery requires us to transport coal first by rail to a seaborne export terminal and then load the coal onto the buyers’ ships. In certain circumstances, the cost of transporting our coal to international buyers can be twice the cost of transporting our coal to domestic buyers.

We assess the performance of our business using certain key metrics, which are described below and analyzed on a period-to -period basis. These key metrics include Adjusted EBITDA, production, tons sold, coal sales realization, and cash cost per ton sold.

Adjusted EBITDA is defined as net income attributable to controlling interests before interest, income taxes, depreciation, depletion, amortization and accretion. Adjusted EBITDA is also adjusted for equity-based compensation, unrealized gains or losses on derivatives, early debt extinguishment costs and for material nonrecurring or other items which may not reflect the trend of future results. Adjusted EBITDA is not a measure of performance defined in accordance with U.S. GAAP. However, management believes that Adjusted EBITDA is useful to investors in evaluating our performance because it is a commonly used financial analysis tool for measuring and comparing companies in our industry in areas of operating performance. Management believes that the disclosure of Adjusted EBITDA offers an additional view of our operations that, when coupled with our U.S. GAAP results and the reconciliation to U.S. GAAP results, provides a more complete understanding of our results of operations and the factors and trends affecting our business. Adjusted EBITDA should not be considered as an alternative to net income, as an indicator of our performance or as an alternative to net cash provided by operating activities as a measure of liquidity. The primary limitation associated with the use of Adjusted EBITDA as compared to U.S GAAP results are (i) it may not be comparable to similarly titled measures used by other companies in our industry, and (ii) it excludes financial information that some consider important in evaluating our performance. We compensate for these limitations by providing a reconciliation of Adjusted EBITDA to U.S. GAAP results, to enable users to perform their own analysis of our operating results.

Coal Sales. The following table summarizes coal sales information for the years ended December 31, 2014 and 2013.

Coal sales increased $152.0 million from the prior year due primarily to record sales volumes, which resulted in $178.0 million of additional coal sales. This increase was offset by a $1.17 per ton, or 2.3%, decrease in coal sales realization per ton. The increase in sales volumes was driven by higher production due to the start-up of the second longwall at our Sugar Camp complex in June 2014. The decline in coal sales realization compared to the prior year was due to a lower mix of international shipments, as well as a small decline in realization per ton on both our domestic and international sales.

Cost of Coal Produced (Excluding Depreciation, Depletion and Amortization). The following table summarizes cost of coal produced (excluding depreciation, depletion and amortization) information for years ended December 31, 2014 and 2013.

Cost of coal produced (excluding depreciation, depletion and amortization) increased $89.0 million, or 24.7% for the year ended December 31, 2014 primarily due to higher sales volumes, which resulted in $60.0 million in higher costs, as well as a $1.34 per ton increase in the cash cost per ton sold due to increased production costs at our Sugar Camp and Hillsboro operations. Our cash cost per ton sold at Sugar Camp was higher due to the introduction of additional continuous miner development units as well as higher roof control, water handling and other longwall-related costs. The increased costs at our Hillsboro mine were primarily a result of an underground fire which halted production for nearly a month and resulted in direct incremental costs of $2.6 million. Additionally, Hillsboro incurred higher subsidence, longwall and roof control costs during the year ended December 31, 2014.

Cost of Coal Purchased. Cost of coal purchased for the year ended December 31, 2014 was $18.2 million, compared to $2.2 million during the year ended December 31, 2013. We purchased coal from third parties during the current year in an effort to optimize margins between our domestic and export sales. The cost per ton to purchase coal is typically higher than our cost per ton to produce coal.

Transportation. Our cost of transportation for the year ended December 31, 2014 increased $28.2 million primarily due to higher sales volumes offset by a $0.39 per ton decrease in the average cost of transportation. The decline in transportation cost per ton was due to a lower percentage of our sales going to international markets during the year offset by higher charges for shortfalls on

minimum contractual throughput volume requirements and an increase in the cash cost of transporting coal through Sitran and Convent Marine Terminal, both of which are affiliated entities.

Depreciation, Depletion and Amortization. Our depreciation, depletion and amortization expense for the year ended December 31, 2014 increased $5.8 million, or 3.6%. The increase is primarily due to additional equipment added at our second longwall mining operation at our Sugar Camp complex, with the start-up of production on June 1, 2014, and $6.5 million of incremental amortization expense to accelerate amortization on certain Hillsboro development assets due to a change in the mine plan.

Impairment of Prepaid Royalties. During the year ended December 31, 2014, we recorded a $34.7 million impairment charge related to certain Hillsboro prepaid royalties which we determined recoupment was improbable based on the remaining period available for recoupment and current coal market conditions.

Selling, General and Administrative. Our selling, general and administrative expense of $33.7 million for the year ended December 31, 2014 increased $1.4 million due to $3.2 million in equity-based compensation expense recorded during the year offset by lower travel-related expenses in 2014.

Gain on Coal Derivatives. We recorded a gain on our coal derivative contracts of $76.3 million for the year ended December 31, 2014 compared to a $2.4 million gain for the year ended December 31, 2013. The increase was due to the significant decline in the API 2 coal index forward curve throughout 2014. Of the $76.3 million gain recorded, $57.1 million represented an unrealized gain and $19.2 million represented a realized gain.

Loss on Early Extinguishment of Debt. The $5.0 million loss on the early extinguishment of debt recognized during the year ended December 31, 2014 was due primarily to the write-off of $2.8 million of debt issuance costs and $1.9 million in unamortized debt discount as a result of the early repayment of $210.0 million of principal on our term loan. The $77.8 million loss recognized during the year ended December 31, 2013 was associated with the early redemption of the 2017 Senior Notes and the write-off of certain unamortized debt issuance costs.

Interest Expense, Net. Interest expense, net for the year ended December 31, 2014 decreased $2.9 million due to a lower effective interest rate on our senior notes resulting from the August 2013 debt refinancing, lower interest expense on our sale-leaseback obligations, incremental interest capitalized in 2014, and lower amortization on debt issuance costs due to the August 2013 debt refinancing transactions. Offsetting the above decreases was incremental interest costs on the term loan issued in August 2013. For the year ended December 31, 2014, we capitalized $5.2 million in interest expense compared to $3.6 million during the prior year. The increase in capitalized interest was due to capital spending on the development of Sugar Camp’s second longwall mine along with the acquisition of an additional set of longwall shields during 2014.

Adjusted EBITDA. Adjusted EBITDA increased $42.2 million, or 11.7%, to $404.5 million for the year ended December 31, 2014 due primarily to higher sales volumes compared to the prior year, offset by lower coal sales realizations and higher production costs during 2014. The table below reconciles net income attributable to controlling interests to Adjusted EBITDA for the years ended December 31, 2014 and 2013.

For a discussion on Adjusted EBITDA, please read Item 7.“Management’s Discussion and Analysis of Financial Condition and Results of Operations—Key Metrics.”

Coal Sales. The following table summarizes coal sales information during the years ended December 31, 2013 and 2012:

Coal sales for the year ended December 31, 2013 of $957.4 million increased $111.5 million, or 13.2%, compared to coal sales of $845.9 million for the year ended December 31, 2012. The increase in coal sales was primarily due to a 4.2 million ton increase in sales volumes driven by the increased production at Sugar Camp and Hillsboro, which came out of development on March 1, 2012 and September 1, 2012, respectively. Partially offsetting the volume increase was a $7.23 per ton decrease in coal sales realization in 2013 due to an increase in domestic shipments at lower prices relative to international sales as well as lower realization on both domestic and international shipments versus prior year due to the roll-off of some high-priced contracts. Tons sold domestically increased 4.5 million tons and tons sold internationally decreased 0.3 million tons as compared to the year ended December 31, 2012. The increased mix of domestic shipments during this period reflected the relative strength of the domestic market to that of the international market.

Cost of Coal Sales (Excluding Depreciation, Depletion and Amortization). The following table summarizes cost of coal sales (excluding depreciation, depletion and amortization) information for the years ended December 31, 2013 and 2012.

Cost of coal produced (excluding depreciation, depletion and amortization) for the year ended December 31, 2013 was $360.9 million, representing an increase of $57.2 million from $303.6 million for the year ended December 31, 2012. The increase in cost of coal sales (excluding depreciation, depletion and amortization) is due to a 29.5% increase in produced tons sold, offset partially by a $1.74 per ton decrease in the cash cost per ton sold. Cash cost per ton sold was lower during the year ended December 31, 2013 due to a full year of operation of our Hillsboro mine which came out of development on September 1, 2012 and substantially improved cash costs at Sugar Camp due to lower production costs versus the prior year. During 2013, Sugar Camp’s operating mine produced with only one supporting continuous miner unit versus two continuous miner units in the prior year. The remaining two continuous miner units were dedicated to the second longwall mine under development, which benefited our cash cost per ton sold for the year ended December 31, 2013.

Transportation. Our cost of transportation for the year ended December 31, 2013 was $197.8 million, an increase of 15.2% compared to $171.7 million for the year ended December 31, 2012. The substantial increase in sales volumes primarily drove the increase in transportation expense over the prior year. Partially offsetting the impact of the sales volume increase was a decline in our average transportation cost per ton due to incremental rail rebates earned during the year ended December 31, 2013 and a higher percentage of domestic sales in 2013 (domestic sales generally carry a significantly lower transportation cost).

Depreciation, Depletion and Amortization. Our depreciation, depletion and amortization expenses for the year ended December 31, 2013 were $161.2 million, an increase of $36.7 million over depreciation, depletion and amortization expenses of $124.6 million for the year ended December 31, 2012. This increase was primarily the result of Sugar Camp and Hillsboro depreciation and amortization expenses being recorded in our consolidated statements of operations for the full year as Sugar Camp and Hillsboro began longwall production on March 1, 2012 and September 1, 2012, respectively. The year ended December 31, 2012 includes only ten months of depreciation and amortization expenses for Sugar Camp and four months of depreciation and amortization expenses for Hillsboro.

Selling, General and Administrative. Our selling, general and administrative expenses for the year ended December 31, 2013 were $32.3 million, a decrease of $9.2 million compared to our selling, general and administrative expenses of $41.5 million for the year ended December 31, 2012. This decrease was due primarily to lower discretionary bonuses paid in 2013 as well as the write-off of $4.3 million in direct costs incurred to pursue an initial public offering during the year ending December 31, 2012.

Gain on Coal Derivatives We recorded a gain on coal derivative contracts of $2.4 million during the year ended December 31, 2013, as compared to a gain of $0.5 million for the year ended December 31, 2012. Of the $2.4 million net gain, $2.5 million relates to contracts that were still outstanding as of December 31, 2013 and therefore the gain was unrealized.

Other Operating Income, Net. In April 2012, we entered into a $10.0 million settlement agreement with a customer related to a coal supply agreement. The settlement proceeds were recorded in other operating income, net in our consolidated statement of operations during the year ended December 31, 2012.

Interest Expense, Net. Our interest expense, net for the year ended December 31, 2013 was $115.9 million, an increase of $33.3 million, or 40.3%, compared to interest expense, net of $82.6 million for the year ended December 31, 2012. Interest expense increased as compared to 2012 due primarily to a decrease in the amount of interest expense capitalized, the incremental interest expense related to $200 million of additional senior notes outstanding during 2013, a full year of interest on the $50.0 million sale-leaseback transaction of Sugar Camp’s loadout facility, and the interest on the $450.0 million term loan issued in August 2013. Partially offsetting these increases was lower interest expense on our Revolving Credit Facility due to lower average borrowings under this arrangement as well as a lower interest rate on our Revolving Credit Facility and 2021 Senior Notes as a result of the 2013 refinancing transactions. For the year ended December 31, 2013, $3.6 million in interest expense was capitalized compared to $19.0 million for the year ended December 31, 2012, as several large development projects transitioned from development during 2012.

Loss on Early Extinguishment of Debt. For the year ended December 31, 2013, we recorded a $77.8 million loss on the early extinguishment of debt to redeem our 2017 Senior Notes, to write-off certain unamortized debt issuance costs, and the unamortized net debt premium of the extinguished and modified debt.

Net Income (Loss) Attributable to Noncontrolling Interests. The increase in net income attributable to noncontrolling interests is due primarily to the throughput agreement executed with Hillsboro Transport, LLC (“Hillsboro Transport”), a consolidated variable interest entity owned by Foresight Reserves, which requires that Hillsboro pay Hillsboro Transport a fee of $0.99 for each ton of coal passed through the loadout in exchange for Hillsboro Transport’s obligation to operate and maintain the loadout. This agreement was executed in August 2013, therefore no such noncontrolling interest income existed in 2012.

Adjusted EBITDA. We realized Adjusted EBITDA of $362.2 million for the year ended December 31, 2013, a $23.8 million, or 7.0%, increase from our Adjusted EBITDA in 2012 of $338.4 million. The increase is largely attributed to higher production and sales levels during 2013 offset by lower coal sales realization during 2013, in addition to the other factors discussed above. The table below reconciles net income attributable to controlling interests to Adjusted EBITDA for the years ended December 31, 2013 and 2012.

For a discussion on Adjusted EBITDA, please read Item 7.“Management’s Discussion and Analysis of Financial Condition and Results of Operations—Key Metrics.”

Our primary uses of cash include, but are not limited to, the cash costs of coal production, capital expenditures, coal reserve lease and royalty payments, production taxes, debt service costs (interest and principal), lease obligations, transportation costs and distributions to our unitholders. We expect that our cash flows from operations and available capacity under our Revolving Credit Facility will continue to support our existing operations for the next 12 months.

Since inception, we have made significant investments in capital expenditures to develop our four mining complexes and related transportation infrastructure which were funded with debt and cash generated from operations. Our operations are capital intensive, requiring investments to expand, maintain or enhance existing operations and to meet environmental and operational regulations. Our future capital spending will be determined by the board of directors of our general partner. Our capital requirements consist of maintenance and expansion capital expenditures. Maintenance capital expenditures are cash expenditures made to maintain our then-current operating capacity or net income as they exist at such time as the capital expenditures are made. Our maintenance capital expenditures can be irregular, causing the amount spent on actual maintenance capital expenditures to differ materially from period to period.

Expansion capital expenditures are cash expenditures made to increase, over the long-term, our operating capacity or net income as they exist at such time as the capital expenditures are made. Development of the second longwall at our Sugar Camp complex was substantially completed with the start-up of the longwall on June 1, 2014. Future longwall development and the associated expansion capital expenditures will be dependent on several factors, including permitting, demand, access to capital, equipment availability and the committed sales position at our existing mining operations. We are currently incurring limited capital costs to pursue permits that would enable us to install our third and fourth longwall mines and related infrastructure at the Sugar Camp complex. In the event that market conditions are unsatisfactory for expansion or if capital markets are unavailable, we are not obligated or committed to use cash for expansion capital expenditures and would adjust the timing and pace of our growth accordingly.

As of December 31, 2014, the total amount outstanding under our long-term debt and capital lease obligations was $1,360.7 million, compared to $1,519.2 million at December 31, 2013. As of December 31, 2014, we had $199.4 million of liquidity comprised of $25.4 million in cash and $174.0 million of available borrowing capacity under our credit facility.

The following is a summary of cash provided by or used in each of the indicated types of activities during the years ended December 31, 2014, 2013, and 2012.

Net cash provided by operating activities increased $56.5 million from the prior year to $236.0 million for the year ended December 31, 2014. The increase in cash provided by operations was primarily due to the usage of $72.1 million of cash in the prior year for the early extinguishment of the 2017 Senior Notes and a $42.2 million increase in Adjusted EBITDA during 2014, offset partially by unfavorable net changes in our working capital accounts primarily due to higher inventory and receivables at December 31, 2014 due to our growth in sales and production from the prior year.

Net cash provided by operating activities was $179.5 million for the year ended December 31, 2013, compared to $209.7 million for the year ended December 31, 2012. The decrease in cash provided by operating activities during 2013 was primarily a result of $72.1 million of cash utilized for the early extinguishment of the 2017 Senior Notes and incremental cash interest expense, offset partially by an increase in Adjusted EBITDA as compared to the year ended December 31, 2012 and net changes in our working capital accounts.

Net cash used in investing activities was $224.1 million for the year ended December 31, 2014, compared to $209.3 million for the year ended December 31, 2013. During 2014, we invested $229.3 million in property, plant, equipment and development. Significant capital expenditures were made in 2014 for the second longwall mine at our Sugar Camp complex, including the purchase of an additional set of longwall shields, the construction of two water treatment plants at our Sugar Camp Complex, and refuse expansion at Hillsboro. We also settled certain outstanding coal derivative contracts during the year ended December 31, 2014 prior to the economically hedged sale transaction occurring; therefore, we recorded $7.3 million of cash proceeds as an investing activity.

For the years ended December 31, 2013 and 2012, we invested $210.7 million and $209.9 million, respectively, in property, plant, equipment and development. Significant capital expenditures were spent on our first Hillsboro and Sugar Camp longwall mines during the year ended December 31, 2012 and for development costs at our second Sugar Camp longwall mine during the year ended December 31, 2013.

Net cash used in financing activities was $9.8 million for the year ended December 31, 2014. During 2014, we received proceeds from our IPO of $322.7 million, net of $27.1 million in underwriter fees and other costs and fees associated with the IPO. Net proceeds from the IPO were used to repay $210.0 million of term loan principal and pay a $115.0 million special distribution to Foresight Reserves and a member of management. We also increased our borrowings under our Revolving Credit Facility by $60.5 million and incurred $24.3 million of incremental indebtedness related to purchase of a new set of longwall shields. In addition, during the year ended December 31, 2014, we repaid $35.0 million of principal under our longwall financing and capital lease arrangements, repaid an additional $1.1 million of term loan principal and paid $54.7 million in additional cash distributions ($49.2 million of which were quarterly distributions to limited partner unitholders subsequent to our IPO).

Net cash provided by financing activities was $25.1 million for the year ended December 31, 2013, compared to $26.5 million used in financing activities for the year ended December 31, 2012. During the year ended December 31, 2013, we received proceeds, net of discounts, of $1,041.2 million from the issuance of the 2021 Senior Notes and $450 million term loan, we increased borrowings under our Revolving Credit Facility by $23.0 million, and we borrowed $31.6 million under an interim longwall financing arrangement, offset by the $600.0 million extinguishment of our outstanding 2017 Senior Notes, the payment of $23.7 million in issuance costs associated with the 2013 Refinancing, the payment of $411.9 million in distributions ($25.0 million of which was accrued for at December 31, 2012), the repayments of $33.7 million of principal under our longwall financing and capital lease arrangements and a $1.1 million repayment on our term loan. The net cash used in financing activities of $26.5 million for the year ended December 31, 2012 was primarily due to $206.0 million in proceeds received from the issuance of the 2017 Senior Notes in October 2012, $50.0 million in proceeds received under the Sugar Camp sales-leaseback financing arrangement with HOD LLC (“HOD”), a subsidiary of NRP, and $58.0 million in proceeds received under a financing arrangement for longwall shields, offset by $88.0 million of net repayments on our prior credit facility, $26.3 million of repayments on short-term debt and our longwall financing and capital lease arrangements, and $219.4 million paid-out in member distributions.

On August 23, 2013, we completed a $600.0 million offering of senior notes which bear interest of 7.875%, paid semiannually each February 15 and August 15, with the entire principal balance due on August 15, 2021 (“2021 Senior Notes”). We utilized the proceeds from the issuance together with the proceeds from our senior secured credit facilities, discussed below, to make a $375.0 million distribution to our members, to refinance the prior credit facility, to purchase, redeem or otherwise acquire all of the 2017 Senior Notes and to pay related transaction costs, fees and expenses. The 2021 Senior Notes are guaranteed on a senior unsecured basis by Foresight Energy LP and all of its operating subsidiaries, other than Foresight Energy Finance Corporation, the co-

issuer of the 2021 Senior Notes. The indenture for the 2021 Senior Notes includes limitations on restricted payments, which may impact the timing and amount of distributions that can be paid to unitholders.

On August 23, 2013, Foresight Energy LLC amended and restated its prior credit facility. The amended and restated credit facilities provide for the five-year revolving credit facility of $500.0 million (the “Revolving Credit Facility”) and a seven-year term loan B facility in an aggregate principal of $450.0 million (the “Term Loan” and, together with the Revolving Credit Facility, the “Senior Secured Credit Facilities”). The Revolving Credit Facility expires on August 15, 2018 and the Term Loan expires on August 15, 2020. The Senior Secured Credit Facilities are guaranteed by all of the domestic operating subsidiaries of Foresight Energy LP.

Borrowings under our Revolving Credit Facility bear interest at a rate equal to, at our option, (1) British Bankers’ Association (as published by Reuters) London Interbank Offered Rate (“LIBOR”) plus an applicable margin ranging from 2.50% to 3.50% or (2) a base rate plus an applicable margin ranging from 1.50% to 2.50%, in each case, determined in accordance with our consolidated net leverage ratio. Borrowings under our Term Loan bear interest of a rate equal to, at our option, (1) British Bankers’ Association (as published by Reuters) LIBOR plus 4.50% or (2) a base rate plus 3.50%, with a LIBOR floor of 1.00% for the Term Loan. We are also required to pay a commitment fee of 0.50% to the lenders under the Revolving Credit Facility in respect of unutilized commitments thereunder. In addition, we are required to pay a fronting fee equal to 0.125% per annum of the amount available to be drawn under letters of credit.

At December 31, 2014, we had borrowings of $319.5 million and $6.5 million in letters of credit outstanding under the Revolving Credit Facility and $237.8 million in principal outstanding under the Term Loan. There was $174.0 million of remaining capacity under the Revolving Credit Facility as of December 31, 2014. The weighted-average effective interest rate on borrowings under the Revolving Credit Facility and Term Loan as of December 31, 2014 was 3.5% and 5.5%, respectively.

The Senior Secured Credit Facilities are subject to customary debt covenants, including a consolidated interest coverage ratio and a consolidated net senior secured leverage ratio. As of December 31, 2014, our consolidated interest coverage ratio and consolidated net senior secured leverage ratio were 3.63x and 1.83x, respectively. Our covenants required a consolidated interest coverage ratio of greater than 2.00x and a consolidated net senior secured leverage ratio of less than 2.75x as of December 31, 2014. Additionally, the Senior Secured Credit Facilities include limitations on restricted payments which may impact the timing and amount of distributions that can be paid to unitholders.

On January 13, 2015, Foresight Energy LP and certain of its wholly-owned subsidiaries, entered into a three-year, $70.0 million receivables securitization program (the “Program”). Under this Program, Foresight subsidiaries will sell their customer trade receivables (the “Receivables”), on a revolving basis, to Foresight Receivables LLC, a wholly-owned special purpose subsidiary of Foresight (the “SPV”). The SPV will then pledge its interests in the Receivables to the Program lenders, which will either make loans or issue letters of credit to, or on behalf of, the SPV. The maximum amount of advances and letters of credit outstanding under the program may not exceed $70 million. The scheduled termination date under the Program is January 12, 2018. The borrowings under the receivables securitization program have two tranches of interest rates that approximate the one-month LIBOR rate plus 0.80% and the Program also carries a commitment fee of 0.40% for unutilized commitments.

We used the initial $57.2 million of borrowings under the securitization program primarily to reduce amounts outstanding under our Revolving Credit Facility.

In November 2014, FELLC entered into a sale-leaseback financing arrangement with a financial institution under which we sold a set of longwall shields and related equipment for $55.9 million and leased the shields back under three individual leases. We account for these leases as capital lease obligations since ownership of the longwall shields and related equipment transfer back to us upon the completion of the leases. These capital lease obligations bear interest at 5.762% and principal and interest payments are due monthly over the five-year terms of the leases. Aggregate termination payments of $2.8 million are due at the end of the lease terms. As of December 31, 2014, $55.1 million was outstanding under these capital lease obligations.

of $63.2 million. In May 2014, the interim longwall financing arrangement and master lease agreement were terminated with the repayment of the $61.3 million outstanding balance.

In March 2012, we entered into a finance agreement with a financial institution to fund the manufacturing of longwall equipment. Upon taking possession of the longwall equipment during the third quarter of 2012, the interim longwall finance agreement was converted into six individual leases with maturities of four and five years beginning on September 1, 2012. The capital lease obligations bear interest ranging from 5.4% to 6.3% and principal and interest payments are due monthly over the terms of the leases. As of December 31, 2014, $30.5 million was outstanding under these capital lease obligations.

In May 2010, Hillsboro Energy LLC, as the borrower, and Foresight Energy LLC, as a guarantor, entered into a credit agreement with a financial institution to provide financing for longwall mining equipment and related parts and accessories. The longwall financing arrangement is collateralized by the longwall mine equipment. Interest accrues on the note at a fixed rate per annum of 5.555% and is due semi-annually in March and September until maturity. Principal is due in 17 equal semi-annual payments through September 30, 2020. The outstanding balance as of December 31, 2014 was $61.9 million.

In January 2010, Sugar Camp Energy LLC, as the borrower, and Foresight Energy LLC, as a guarantor, entered into a credit agreement with a financial institution to provide financing for longwall equipment and related parts and accessories. The longwall financing arrangement is collateralized by the longwall mining equipment. Interest accrues on the note at a fixed rate per annum of 5.78% and is due semi-annually in June and December until maturity. Principal is due in 17 equal semi-annual payments through June 30, 2020. The outstanding balance as of December 31, 2014 was $61.6 million.

The 5.78% and 5.555% longwall financing arrangements contain certain financial covenants that require, among other things, maintenance of minimum amounts and compliance with a net senior secured interest coverage and leverage ratios, consistent with those in our Revolving Credit Facility. We met the required financial covenants at December 31, 2014, and we believe we are currently in compliance.

In the first quarter of 2009, Macoupin sold certain of its coal reserves and rail facility assets to WPP, LLC (“WPP”), a subsidiary of NRP, and leased them back. The gross proceeds from this transaction of $143.5 million were used for capital expenditures relating to the rehabilitation of Macoupin and for other capital items. As Macoupin has continuing involvement in the assets sold, the transaction is treated as a financing arrangement. At December 31, 2014, the outstanding balance of the sale-leaseback financing arrangement was $143.5 million.

In the first quarter of 2012, Sugar Camp sold certain rail facility assets to HOD, LLC (“HOD”), a subsidiary of NRP, and leased them back. The gross proceeds from this transaction were $50.0 million and were used for capital expenditures, to pay down our revolving credit balance and for general corporate purposes. As Sugar Camp has continuing involvement in the assets sold, the transaction is treated as a financing arrangement. At December 31, 2014, the outstanding balance of the sale-leaseback financing arrangement was $50.0 million.

In the normal course of business, we are a party to certain off-balance sheet arrangements, including operating leases, coal reserve leases, take-or-pay transportation obligations, indemnifications, and financial instruments with off-balance sheet risk, such as bank letters of credit and surety bonds. Liabilities related to these arrangements are generally not reflected in our consolidated balance sheets and, except for the coal reserve leases, take-or-pay transportation obligations and operating leases, we do not expect any material impact on our cash flows, results of operations or financial condition to result from these off-balance sheet arrangements.

From time to time we use bank letters of credit to secure our obligations for certain contracts and other obligations. At December 31, 2014, we had $6.5 million in letters of credit outstanding to secure our workers’ compensation insurance program and a royalty obligation.

We use surety bonds to secure reclamation and other miscellaneous obligations. As of December 31, 2014, we had $54.8 million of outstanding surety bonds with third parties. These bonds were primarily in place to secure post-mining reclamation. We are not required to post collateral for these bonds.

The following is a summary of our significant future contractual obligations as of December 31, 2014, by year:

	Total		Less than 1 year		1 - 3 years		3 - 5 years		More than 5 years
	(In Millions)
Long-term debt (principal and interest)(1)	$	1,752.0	$	100.6	$	197.6	$	496.8	$	957.0
Sale-leaseback financing arrangement(2)		310.3		21.0		42.0		42.0		205.3
Capital lease obligations (principal and interest)		96.4		27.0		42.9		26.5		—
Operating lease obligations		8.5		3.5		3.9		0.9		0.2
Take-or-pay transportation arrangements(3)		501.0		70.3		139.0		140.0		151.7
Coal reserve lease and royalty obligations(4)		624.5		59.7		119.3		119.3		326.2
Unconditional purchase obligations(5)		33.2		33.2		—		—		—
Total(6)	$	3,325.9	$	315.3	$	544.7	$	825.5	$	1,640.4

We lease certain surface rights, mineral reserves, mining, transportation, and other equipment under various lease agreements with related entities under common ownership, NRP and its subsidiaries, and other independent third parties in the normal course of business. The mineral reserve leases can generally be renewed as long as the mineral reserves are being developed and mined until all economically recoverable reserves are depleted or until mining operations cease. The leases require a production royalty at the greater amount of a base amount per ton or a percent of the gross selling price of the coal. Generally, the leases contain provisions that require the payment of minimum royalties regardless of the volume of coal produced or the level of mining activity. The minimum royalties are generally recoupable against production royalties over a contractually defined period of time (generally five to ten years). Some of these agreements also require overriding royalty and/or wheelage payments. Under the terms of some mineral reserve mining leases, we are to use commercially reasonable efforts to acquire additional mineral reserves in certain properties as defined in the agreements and are responsible for the acquisition costs and the assets are to be titled to the lessor. Transportation throughput agreements generally require a per ton fee amount for coal transported and contain certain escalation clauses and/or renegotiation clauses. For certain transportation assets, we are responsible for operations, repairs, and maintenance and for keeping transportation facilities in good working order. Surface rights, mining, and other equipment leases require monthly payments based upon the specified agreements. Certain of these leases provide options for the purchase of the property at various times during the life of the lease, generally at its then fair market value. We also lease rail cars, certain office space and equipment under leases with varying expiration dates.

See Item 13.“Certain Relationships and Related Party Transactions and Director Independence” for a discussion of the above leases and agreement with affiliated parties.

Our discussion and analysis of our financial condition, results of operations, liquidity and capital resources is based on our financial statements, which have been prepared in accordance with U.S. GAAP, which requires that we make estimates and judgments that affect the reported amounts of assets, liabilities, revenues and expenses, and the related disclosure of contingent assets and liabilities. We base these estimates on historical experience and on various other assumptions that we consider reasonable under the circumstances. On an ongoing basis we evaluate our estimates. Actual results may differ from these estimates. Of these significant accounting policies, we believe the following may involve a higher degree of judgment or complexity.

Sale-Leaseback Financing Arrangements. In the first quarter of 2009, Macoupin sold certain of its coal reserves to WPP, and leased them back. The gross proceeds from this transaction were $143.5 million, and were used for capital expenditures relating to the rehabilitation of the Macoupin mine and for other capital items. Similarly, in the first quarter of 2012, Sugar Camp sold certain rail facilities to HOD, and leased them back. The gross proceeds from this transaction were $50.0 million, and were used for capital expenditures, to pay down our revolving credit facility and for general corporate purposes. In both transactions, because we had continuing involvement in the assets sold, the transactions were treated as sale-leaseback financing arrangements.

Interest is accrued on the outstanding principal amounts of the financing arrangements using an implied interest rate, which was initially determined at inception of the lease and is adjusted for changes in future expected amounts and timing of payments based on the mine plans and also, for the Macoupin sale-leaseback only, the future expected sales price of its coal. Payments are applied first against accrued interest and any excess is then applied against the outstanding principal. Revisions to the mine plans, which occur periodically as changes are made to estimates of the quantity and the timing of tons to be mined, will impact the effective interest rate. We account for such changes by adjusting in the current period, the life-to-date interest previously recorded on the sale-leaseback to reflect the new effective interest rate as if it was applied from the inception of the transaction (i.e., retroactively applied). The implied effective interest rate was approximately 13.9% and 14.2% as of December 31, 2014 and 2013, respectively, on the Macoupin sale-leaseback financing arrangement and 13.9% and 14.3% for the Sugar Camp sale-leaseback financing arrangement as of December 31, 2014 and 2013, respectively. If there is a material change to the mine plans, the impact of a change in the effective interest rate to the consolidated statements of operations could be significant.

Prepaid Royalties. Prepaid royalties consist of recoupable minimum royalty payments under various lease agreements. As of December 31, 2014 and 2013, we had recorded on the consolidated balance sheets $68.3 million and $79.6 million, respectively, of prepaid royalties. We continually evaluate our ability to recoup prepaid royalty balances which evaluation includes, among other things, assessing mine production plans, sales commitments, current and forecasted future coal market conditions, and remaining years available for recoupment. The contractual recoupment periods are generally five to ten years from the payment date. In the fourth quarter of 2014, we recorded a $34.7 million impairment charge to reserve against a contractual prepaid royalty between Hillsboro and WPP. We recorded the impairment charge given that recoupment of certain prior minimum royalty payments was determined improbable given the remaining time available under the five-year recoupment periods and our expected demand for Hillsboro coal based on current and forecasted near-term market conditions, which are impacted by natural gas prices, weather, economic conditions and the regulatory environment.

Asset Retirement Obligations. Our asset retirement obligations (“ARO”) consist of estimated spending related to reclaiming surface land and support facilities at our mines in accordance with federal and state reclamation laws as required by each mining permit. Obligations are incurred at the time mine development commences or when construction begins in the case of support facilities, refuse areas and slurry ponds.

The liability is determined using discounted cash flow techniques and is reduced to its present value at the end of each period. We estimate our ARO liabilities for final reclamation and mine closure based upon detailed engineering calculations of the amount and timing of the future cash cost for a third party to perform the required work. Spending estimates are escalated for inflation, and market risk premium, and then discounted at the credit-adjusted, risk-free rate. The credit-adjusted, risk-free interest rates were 6.6%, 8.8%, and 7.6% at December 31, 2014, 2013, and 2012, respectively. We record an ARO asset associated with the discounted liability for final reclamation and mine closure. Accretion on the ARO begins at the time the liability is incurred. Upon initial recognition of a liability, a corresponding amount is capitalized as part of the carrying amount of the related long-lived asset. The ARO asset for equipment, structures, buildings, and mine development is amortized over its expected life on a units-of-production basis. The ARO liability is then accreted to the projected spending date. As changes in estimates occur (such as mine plan revisions, changes in estimated costs, or changes in timing of the performance of reclamation activities), the revisions to the obligation and asset are recognized at the appropriate credit-adjusted, risk-free rate.

On at least an annual basis, we review our entire reclamation liability and make necessary adjustments for permit changes as granted by state authorities, changes in the timing of reclamation activities and revisions to cost estimates, the occurrence of new

liabilities from additional disturbances and productivity assumptions. Any difference between the recorded amount of the liability and the actual cost of reclamation will be recognized as a gain or loss when the obligation is settled. At December 31, 2014, our balance sheet reflected asset retirement obligations of $35.6 million, including amounts classified as a current liability. We estimate the aggregate undiscounted cost of final mine closures, at 2014 costs, to be approximately $67.4 million as of December 31, 2014.

Variable Interest Entities (VIEs). We employ contractors to provide labor for our mines and coal processing facilities. In accordance with US GAAP, our consolidated financial statements include entities considered variable interest entities (“VIEs”) for which we are the primary beneficiary. These entities are deemed to be our affiliates and generally own no equipment, real property or other intangible assets and each holds a contract, and in some instances an operator assignment, to provide contract labor services solely to Foresight Energy LP subsidiaries.

VIEs are primarily entities that lack sufficient equity to finance their activities without additional financial support from other parties or whose equity holders, as a group, lack one or more of the following characteristics: (a) direct or indirect ability to make decisions, (b) obligation to absorb expected losses, or (c) right to receive expected residual returns. VIEs must be evaluated quantitatively and qualitatively to determine the primary beneficiary, which is the reporting entity that has (a) the power to direct activities of a VIE that most significantly impact the VIEs economic performance and (b) the obligation to absorb losses of the VIE that could potentially be significant to the VIE or the right to receive benefits from the VIE that could potentially be significant to the VIE. The primary beneficiary is required to consolidate the VIE for financial reporting purposes.

To determine a VIE’s primary beneficiary, we perform a qualitative assessment to determine which party, if any, has the power to direct activities of the VIE and the obligation to absorb losses and/or receive its benefits. This assessment involves identifying the activities that most significantly impact the VIE’s economic performance and determine whether it, or another party, has the power to direct those activities. When evaluating whether we are the primary beneficiary of a VIE, and must therefore consolidate the entity, we perform a qualitative analysis that considers the design of the VIE, the nature of our involvement and the variable interests held by us and other parties. If that evaluation is inconclusive as to which party absorbs a majority of the entity’s expected losses or residual returns, a quantitative analysis would be performed to determine the primary beneficiary.

In April 2014, the Financial Accounting Standards Board (“FASB”) issued Accounting Standards Update (“ASU”) 2014-08, Reporting Discontinued Operations and Disclosures of Disposals of Components of an Entity. ASU 2014-08 changes the requirements for reporting discontinued operations by updating the criteria for determining discontinued operations and modifies the disclosure requirements. ASU 2014-08 is effective for annual and interim periods beginning after December 15, 2014 and we do not expect the adoption will have a material impact on our consolidated financial statements.

In May 2014, the FASB issued ASU 2014-09, Revenue from Contracts with Customers, to clarify the principles used to recognize revenue for all entities. The guidance is effective for annual and interim periods beginning after December 15, 2016. Early adoption is not permitted. We are in the process of evaluating the effects, if any, adoption of this guidance will have on our consolidated financial statements.

In August 2014, the FASB issued ASU 2014-15, Disclosure of Uncertainties about an Entity’s Ability to Continue as a Going Concern, which requires management of a company to evaluate whether there is substantial doubt about the company’s ability to continue as a going concern. This ASU is effective for the annual reporting period ending after December 15, 2016, with early adoption permitted. This standard is not currently expected to have a material effect on the Partnership's financial statement disclosures, though the ultimate impact will be dependent on the Partnership's financial condition and expected operating outlook.

We define market risk as the risk of economic loss as a consequence of the adverse movement of market rates and prices. We believe our principal market risks include commodity price risk, interest rate risk and credit risk, which are disclosed below.

We have commodity price risk as a result of changes in the market value of our coal. We try to minimize this risk by entering into fixed price coal supply agreements and, from time to time, commodity hedge agreements. As of December 31, 2014, we had the following contracted sales commitments for the years ending December 31, 2015 and 2016:

As of December 31, 2014, we have 3.4 million tons economically hedged with forward coal derivative contracts tied to the API 2 coal price index to partially mitigate coal price risk through 2017. The impact of our economic hedges to fix the selling price on unpriced (or index-based) coal sales contracts and forecasted sales is not reflected in the table above. A 10% change in the API 2 index would result in a $34.4 million change in the fair value of these derivative contracts.

We are exposed to market risk associated with interest rates due to our existing level of indebtedness. At December 31, 2014, of our $1,360.7 million in long-term debt and capital lease obligations outstanding, $557.3 million of outstanding borrowings have interest rates that fluctuate based on changes in the market interest rates. A one percentage point increase in the interest rates related to variable interest borrowings would result in an annualized increase in interest expense of approximately $3.3 million.

We have credit risk associated with our customers and counterparties in our coal sales agreements and commodity hedge contracts. We have procedures in place to assist in determining the creditworthiness and credit limits for such customers and counterparties. Generally, credit is extended based on an evaluation of the customer’s financial condition. Collateral is not generally required, unless credit cannot be established. At December 31, 2014, no allowance was recorded for uncollectible accounts receivable as all amounts were deemed collectible.

We have audited the accompanying consolidated balance sheets of Foresight Energy LP (the “Partnership”) as of December 31, 2014 and 2013, and the related consolidated statements of operations, partners’ capital (deficit), and cash flows for each of the three years in the period ended December 31, 2014. Our audits also included the financial statement schedule listed in the Index at Item 15(a). These financial statements are the responsibility of the Partnership ’s management. Our responsibility is to express an opinion on these financial statements based on our audits.

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

In our opinion, the financial statements referred to above present fairly, in all material respects, the consolidated financial position of Foresight Energy LP at December 31, 2014 and 2013, and the consolidated results of its operations and its cash flows for each of the three years in the period ended December 31, 2014, in conformity with U.S. generally accepted accounting principles. Also, in our opinion, the related financial statement schedule, when considered in relation to the basic financial statements taken as a whole, presents fairly, in all material respects, the information set forth therein.

	December 31,			December 31,
	2014			2013
	(In Thousands)
Assets
Current assets:
Cash and cash equivalents	$	25,406		$	23,284
Accounts receivable		80,763			58,987
Due from affiliates		574			368
Inventories		92,402			71,290
Prepaid expenses		2,134			3,028
Prepaid royalties		8,380			6,330
Deferred longwall costs		23,224			14,265
Coal derivative assets		36,080			1,976
Other current assets		6,302			6,568
Total current assets		275,265			186,096
Property, plant, equipment and development, net		1,473,063			1,414,074
Prepaid royalties		59,967			73,242
Coal derivative assets		24,957			912
Other assets		31,970			35,847
Total assets	$	1,865,222		$	1,710,171
Liabilities and partners’ capital (deficit)
Current liabilities:
Current portion of long-term debt and capital lease obligations	$	44,143		$	70,034
Accrued interest		25,136			27,645
Accounts payable		59,937			50,155
Accrued expenses and other current liabilities		37,602			37,515
Due to affiliates		15,878			9,572
Total current liabilities		182,696			194,921
Long-term debt and capital lease obligations		1,316,528			1,449,179
Sale-leaseback financing arrangements		193,434			193,434
Asset retirement obligations		31,373			20,416
Other long-term liabilities		5,508			337
Total liabilities		1,729,539			1,858,287
Limited partners' capital (deficit):
Common unitholders (64,831 units outstanding as of December 31, 2014)		238,925			—
Subordinated unitholders (64,739 units outstanding as of December 31, 2014)		(111,169	)		—
Total limited partners' capital		127,756			—
Predecessor members' deficit		—			(157,356	)
Noncontrolling interests		7,927			9,240
Total partners' capital (deficit)		135,683			(148,116	)
Total liabilities and partners' capital (deficit)	$	1,865,222		$	1,710,171

See accompanying notes.

	For the Year Ended December 31,
	2014			2013			2012
	(In Thousands, Except per Unit Data)
Coal sales	$	1,109,404		$	957,412		$	845,886
Costs and expenses:
Cost of coal produced (excluding depreciation, depletion and amortization)		449,905			360,861			303,638
Cost of coal purchased		18,232			2,163			6,163
Transportation		226,029			197,839			171,679
Depreciation, depletion and amortization		167,039			161,216			124,552
Accretion on asset retirement obligations		1,621			1,527			1,368
Impairment of prepaid royalties		34,700			—			—
Selling, general and administrative		33,679			32,291			41,528
Gain on coal derivatives		(76,330	)		(2,392	)		(534	)
Other operating income, net		(2,527	)		(280	)		(10,759	)
Operating income		257,056			204,187			208,251
Other expenses:
Loss on early extinguishment of debt		4,979			77,773			—
Interest expense, net		113,030			115,897			82,580
Net income		139,047			10,517			125,671
Less: net income (loss) attributable to noncontrolling interests		3,847			2,236			(160	)
Net income attributable to controlling interests		135,200		$	8,281		$	125,831
Less: predecessor net income attributable to controlling interests prior to initial public offering		65,008
Net income subsequent to initial public offering attributable to limited partner units (June 23, 2014 through December 31, 2014)	$	70,192

Net income subsequent to initial public offering available to limited partner units - basic and diluted:
Common unitholders	$	35,154
Subordinated unitholders	$	35,038

Net income subsequent to initial public offering per limited partner unit - basic and diluted:
Common unitholders	$	0.54
Subordinated unitholders	$	0.54

Weighted average limited partner units outstanding - basic and diluted:
Common units		64,790
Subordinated units		64,739

Distribution declared per limited partner unit	$	0.38


See accompanying notes.

	Limited Partners
	Common			Number of		Subordinated			Number of		Predecessor Members'			Noncontrolling			Total Partners'
	Unitholders' Capital			Common Units		Unitholders' Capital			Subordinated Units		Equity (Deficit)			Interests			Capital (Deficit)
	(In Thousands, Except Unit Data)
Balance at January 1, 2012	$	—			—	$	—			—	$	395,124		$	(919	)	$	394,205
Net income (loss)		—			—		—			—		125,831			(160	)		125,671
Non-cash member contribution		—			—		—			—		4,632			—			4,632
Cash distributions		—			—		—			—		(244,234	)		(171	)		(244,405	)
Balance at December 31, 2012	$	—			—	$	—			—	$	281,353		$	(1,250	)	$	280,103
Net income		—			—		—			—		8,281			2,236			10,517
Consolidation of variable interest entities		—			—		—			—		—			10,120			10,120
Non-cash distributions		—			—		—			—		(61,990	)		—			(61,990	)
Cash distributions		—			—		—			—		(385,000	)		(1,866	)		(386,866	)
Balance at December 31, 2013	$	—			—	$	—			—	$	(157,356	)	$	9,240		$	(148,116	)
Net income prior to initial public offering		—			—		—			—		65,008			1,781			66,789
Non-cash distributions		—			—		—			—		(12,187	)		—			(12,187	)
Contribution of net assets to Foresight Energy LP		(51,354	)		—		(53,524	)		—		104,878			—			—
Issuance of common units, net of offering costs		322,813			64,738,895		—			64,738,895		—			—			322,813
Cash distributions		(71,537	)		—		(92,683	)		—		(343	)		(5,160	)		(169,723	)
Net income subsequent to initial public offering		35,154			—		35,038			—		—			2,066			72,258
Equity-based compensation		5,024			—		—			—		—			—			5,024
Issuance of equity-based awards		—			92,417		—			—		—			—			—
Distribution equivalent rights on LTIP awards		(231	)		—		—			—		—			—			(231	)
Net settlement of withholding taxes on issued LTIP awards		(944	)		—		—			—		—			—			(944	)
Balance at December 31, 2014	$	238,925			64,831,312	$	(111,169	)		64,738,895	$	—		$	7,927		$	135,683

See accompanying notes.

	For the Year Ended December 31,
	2014			2013			2012
	(In Thousands)
Cash flows from operating activities
Net income	$	139,047		$	10,517		$	125,671
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation, depletion and amortization		167,039			161,216			124,552
Amortization of debt issuance costs and debt premium/discount		7,022			7,574			8,235
Equity-based compensation		4,749			—			4,632
Unrealized gain on coal derivatives		(57,126	)		(2,453	)		(534	)
Impairment of prepaid royalties		34,700			—			—
Non-cash loss on early extinguishment of debt		4,681			5,625			—
Other		(5,248	)		(490	)		5,934
Changes in operating assets and liabilities:
Accounts receivable		(21,776	)		9,533			(36,463	)
Due from/to affiliates, net		6,117			(1,190	)		(7,593	)
Inventories		(13,893	)		12,095			(19,397	)
Prepaid expenses and other current assets		(7,799	)		(6,323	)		3,808
Prepaid royalties		(23,475	)		(17,064	)		(29,646	)
Coal derivative assets and liabilities		(1,891	)		(499	)		—
Accounts payable		9,628			1,449			2,057
Accrued interest		(2,509	)		(2,695	)		12,149
Accrued expenses and other current liabilities		1,166			4,847			17,233
Other		(4,392	)		(2,616	)		(947	)
Net cash provided by operating activities		236,040			179,526			209,691
Cash flows from investing activities
Investment in property, plant, equipment and development		(229,251	)		(210,726	)		(209,937	)
Acquisition of an affiliate		(3,822	)		—			—
Proceeds from sale of equipment		1,619			465			2,898
Settlement of certain coal derivatives		7,345			986			—
Net cash used in investing activities		(224,109	)		(209,275	)		(207,039	)
Cash flows from financing activities
Net increase (decrease) in borrowings under revolving credit facility		60,500			23,000			(88,000	)
Proceeds from other long-term debt and capital lease obligations		85,620			1,072,772			264,007
Payments on other long-term debt and capital lease obligations		(307,607	)		(634,863	)		(19,663	)
Payments on short-term debt		—			—			(6,627	)
Proceeds from sale-leaseback financing arrangement		—			—			49,950
Distributions paid		(169,723	)		(411,891	)		(219,405	)
Proceeds from issuance of common units (net of underwriters' discount)		329,875			—			—
Initial public offering costs paid (other than underwriters' discount)		(7,206	)		(144	)		(3,079	)
Debt issuance costs paid		(297	)		(23,729	)		(3,708	)
Other		(971	)		—			—
Net cash (used in) provided by financing activities		(9,809	)		25,145			(26,525	)
Net increase (decrease) in cash and cash equivalents		2,122			(4,604	)		(23,873	)
Cash and cash equivalents, beginning of period		23,284			27,888			51,761
Cash and cash equivalents, end of period	$	25,406		$	23,284		$	27,888

See accompanying notes.

As used in this report, the terms “Foresight Energy LP,” “FELP,” the “Partnership,” “we,” “us” or like terms, refer to the combined results (as described below) of Foresight Energy LP and Foresight Energy LLC and its consolidated subsidiaries and affiliates, unless the context otherwise requires or where otherwise indicated. The information presented in this Annual Report on Form 10-K contains, for all periods presented, the audited combined financial results of Foresight Energy LP and Foresight Energy LLC (“FELLC”), our predecessor for accounting purposes (the “Predecessor”), and variable interest entities (“VIEs”) for which FELLC or its subsidiaries are the primary beneficiary. Prior to June 23, 2014, FELP had no operating or cash flow activity and no recorded net assets.

FELLC, a limited liability company, was formed in September 2006 for the development, mining, transportation and sale of coal. Prior to June 23, 2014, Foresight Reserves, L.P. (“Foresight Reserves”) owned 99.333% of FELLC and a member of management owned 0.667%. In January 2012, Foresight Energy LP (formerly named Foresight Energy Partners LP), a Delaware limited partnership, and Foresight Energy GP LLC (“general partner” or “FEGP”), a Delaware limited liability company, were formed. FELP was formed to own FELLC and FEGP was formed to be the general partner of FELP.

On June 23, 2014, in connection with the initial public offering of FELP, Foresight Reserves and a member of management contributed their ownership interests in FELLC to FELP for which they were issued common and subordinated units in FELP. Because this transaction was between entities under common control, the contributed assets and liabilities of FELLC were recorded in the consolidated financial statements at FELLC’s historical cost. See Note 3 for information regarding our initial public offering. Subsequent to the initial public offering, FELP is managed by FEGP.

The Partnership operates in a single reportable segment and currently operates four underground mining complexes in the Illinois Basin: Williamson Energy, LLC (“Williamson”); Sugar Camp Energy, LLC (“Sugar Camp”); Hillsboro Energy, LLC (“Hillsboro”); and Macoupin Energy, LLC (“Macoupin”). Our coal is sold to a diverse customer base, including electric utility and industrial companies primarily in the eastern United States, as well as overseas markets.

Intercompany transactions, including those between consolidated VIEs, FELP and its consolidated subsidiaries, are eliminated in consolidation.

The preparation of financial statements in conformity with U.S. generally accepted accounting principles (“U.S. GAAP”) requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities at the date of the financial statements and the reported amounts of income and loss during the reporting period. Actual results could differ from those estimates.

Once mines are in production, coal sales include sales to customers of coal produced and, from time to time, the re-sale of coal purchased from third parties. The Partnership recognizes sales at the time legal title and risk of loss pass to the customer at contracted amounts that are fixed or determinable. For domestic coal sales, this generally occurs when coal is loaded onto railcars at the mine or onto barges at terminals. For coal sales to international markets, this generally occurs when coal is loaded onto an ocean vessel. Quality and weight adjustments are recorded as necessary based on contract specifications as a reduction or increase to coal sales and accounts receivable.

Costs related to the handling and transporting of coal to the point of sale are included in coal inventory in the consolidated balance sheets. Upon the recognition of the sale, these costs are included in transportation expenses in the consolidated statements of operations.

The Partnership considers cash deposits with original maturities of less than three months to be cash and cash equivalents. Cash and cash equivalents are stated at cost, which approximates fair value.

The Partnership evaluates the need for an allowance for uncollectible receivables based on a review of account balances that are likely to be uncollectible, as determined by such variables as customer creditworthiness, the age of the receivables and disputed amounts. Historically, credit losses have been insignificant. At December 31, 2014 and 2013, no allowance was recorded for uncollectible accounts receivable as all amounts were deemed collectible.

Inventories are valued at the lower of average cost or market. Parts and supplies inventory consists of spare parts for equipment and supplies used in the mining process. Raw coal represents coal stockpiles that require processing through a preparation plant prior to shipment to a customer. Clean coal represents coal stockpiles that will be sold in their current condition. Coal inventory costs include labor, equipment costs, supplies, transportation costs incurred prior to the transfer of title to customers, depreciation, depletion, amortization and direct mine operating overhead.

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

Prepaid royalties consist of recoupable minimum royalty payments due under various lease agreements entered into by the Partnership. Prepaid royalties expected to be recouped within one year are classified as current assets in the Partnership’s consolidated balance sheets. The Partnership continually evaluates its ability to recoup prepaid royalty balances, which includes, among other factors, assessing mine production plans, sales commitments, future coal market conditions and remaining years available for recoupment. The contractual recoupment periods on the prepaid royalty balances generally range from five to ten years from the date the minimum royalty was paid.

Property, plant and equipment are recorded at cost. Costs that extend the useful lives or increase the productivity of the assets are capitalized, while normal repairs and maintenance that do not extend the useful life or increase the productivity of the asset are expensed as incurred. Asset retirement obligations for the various assets have been recorded as components of the specific assets to which they relate. Interest costs applicable to major additions are capitalized during the construction period. Interest costs capitalized into property, plant, equipment and development, net for the years ended December 31, 2014, 2013, and 2012, were $5.2 million, $3.6 million, and $19.0 million, respectively. Property, plant and equipment are depreciated using the straight-line method over the estimated useful lives of the assets. Machinery and equipment under capital lease agreements are amortized using the straight-line method over the useful lives of the assets given that, in each case, ownership transfers at the end of the lease terms. The cost of acquiring land (subsidence) rights and mineral rights is amortized using the units-of-production method over the mineral reserves benefited by the costs. The estimated useful lives of machinery and equipment, buildings and structures and other categories are as follows:

Costs of developing new mines or significantly expanding the capacity of existing mines are capitalized and amortized using the units-of-production method over the mineral reserves benefited by the development. Costs related to locating coal deposits and evaluating the economic viability of such deposits are expensed as incurred. During the development phase, the Partnership establishes access to the mineral reserves and makes other preparations for commercial production. Development costs principally include clearing land, building roads, sinking shafts, driving slopes and developing refuse areas, ventilation and transportation passageways at the mines. Development costs also include the build-out of the Partnership’s transportation infrastructure. Costs incurred during the development phase are capitalized and proceeds from the incidental sale of coal during development are recorded as a reduction of the related mine development costs. For reporting in the statements of cash flows, cash expended in the investment in mining rights, equipment and

development during the development phase is reported net of capitalized coal sales. Mines in development included the first and second longwalls at Sugar Camp through March 1, 2012 and June 1, 2014, respectively, and the first longwall at Hillsboro through September 1, 2012.

The Partnership records impairment losses on depreciable assets used in operations when events and circumstances indicate that assets might be impaired and the undiscounted cash flows estimated to be generated by those assets are less than their carrying amounts. Impairment losses are measured by comparing the estimated fair value of the impaired asset to its carrying amount. There were no impairment losses recorded during the years ended December 31, 2014, 2013 or 2012.

The Partnership capitalizes costs incurred in connection with the issuance of debt and the establishment of credit facilities and capital leasing arrangements. 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. Amortization expense of $6.1 million, $7.7 million and $8.1 million is included in interest expense for the years ended December 31, 2014, 2013, and 2012, respectively. As of December 31, 2014 and 2013, unamortized debt issuance costs of $24.6 million and $33.6 million, respectively, are included in other assets in the consolidated balance sheets.

The Partnership is party to two arrangements in which it sold assets to an affiliate and immediately leased those assets back from the affiliates. Because the Partnership had continued involvement in the assets sold, the proceeds received on the sale of the assets were recorded as long-term financing liabilities in our consolidated balance sheets. Under both of these arrangements, the Partnership pays a fixed minimum payment, as well as contingent payments for volumes in excess of the contractual minimum payments. Interest is accrued on the outstanding principal amounts of the financing arrangements using an implied interest rate, which was initially determined at inception of the lease and is adjusted for changes in expected amounts and timing of future payments based on the mine plans. Payments are first applied against accrued interest and any excess is applied against the outstanding principal. The Partnership accounts for such changes by adjusting in the current period, the life-to-date interest previously recorded on the sale-leaseback to reflect the new effective interest rate as if it was applied from the inception of the transaction (i.e., retroactively applied). If there is a material change to the mine plans, the impact of a change in the effective interest rate to the consolidated statements of operations could be significant.

The Partnership’s asset retirement obligations (“ARO”) consist primarily of spending estimates related to reclaiming surface land, refuse areas, slurry ponds and support facilities at the Partnership’s underground mines in accordance with federal and state reclamation laws as required by each mining permit. These obligations are typically incurred at the time development of a mine commences for underground mines or when construction begins for support facilities, refuse areas and slurry ponds. The Partnership estimates its ARO for final reclamation and mine closure based upon detailed engineering calculations of the amount and timing of the future cash spending for a third party to perform the required work. Spending estimates are escalated for inflation and a market risk premium and then discounted at a credit-adjusted, risk-free rate. Upon initial recognition of a liability, a corresponding amount is capitalized as part of the carrying value of the related long-lived asset. Over time, the liability is accreted to its present value and the capitalized cost is amortized over the useful life of the related asset on a units-of-production basis. As changes in estimates occur (such as mine plan revisions, changes in estimated costs or changes in timing of the performance of reclamation activities), the revisions to the obligation and asset are recognized at the appropriate credit-adjusted, risk-free interest rate.

The Partnership utilizes derivative financial instruments principally to manage exposures to coal prices. The Partnership records the fair value of each instrument as either an asset or liability in the consolidated balance sheets and the change in fair value of each instrument is recorded in the consolidated statements of operations.

Coal contracts provide for the physical purchase or sale of coal in quantities expected to be used or sold by the Partnership over a reasonable period in the normal course of business, and are not recognized on the consolidated balance sheets.

Fair value is defined as 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. A fair value hierarchy has been established that prioritizes the inputs to valuation techniques used to measure fair value.

The hierarchy, as defined below, gives the highest priority to unadjusted quoted prices in active markets for identical assets or liabilities and the lowest priority to unobservable inputs.

Level 1 is defined as observable inputs, such as quoted prices in active markets for identical assets.

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

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

The carrying value of cash and cash equivalents, accounts receivable, and accounts payable approximate fair value due to the short-term nature of these instruments.

VIEs are primarily entities that lack sufficient equity to finance their activities without additional financial support from other parties or whose equity holders, as a group, lack one or more of the following characteristics: (a) direct or indirect ability to make decisions, (b) obligation to absorb expected losses or (c) right to receive expected residual returns. VIEs must be evaluated quantitatively and qualitatively to determine the primary beneficiary, which is the reporting entity that has (a) the power to direct activities of a VIE that most significantly impact the VIEs economic performance and (b) the obligation to absorb losses of the VIE that could potentially be significant to the VIE or the right to receive benefits from the VIE that could potentially be significant to the VIE. The primary beneficiary is required to consolidate the VIE for financial reporting purposes.

To determine a VIE's primary beneficiary, the Partnership performs a qualitative assessment to determine which party, if any, has the power to direct activities of the VIE and the obligation to absorb losses and/or receive its benefits. This assessment involves identifying the activities that most significantly impact the VIE's economic performance and determine whether it, or another party, has the power to direct those activities. When evaluating whether the Partnership is the primary beneficiary of a VIE, the Partnership performs a qualitative analysis that considers the design of the VIE, the nature of the Partnership’s involvement and the variable interests held by other parties. If that evaluation is inconclusive as to which party absorbs a majority of the entity’s expected losses or residual returns, a quantitative analysis would be performed to determine the primary beneficiary. The income attributable to consolidated variable interest entities is recorded as net income attributable to noncontrolling interests in the consolidated statements of operations.

We are not a taxable entity for federal or state income tax purposes; the tax effect of our activities accrues to the unitholders. While Section 7704(a) of the tax code generally provides that publicly traded partnerships will be treated as corporations for federal income tax purposes, if 90% or more of a partnership’s gross income for every taxable year it is publicly traded consists of “qualifying income,” the partnership may continue to be treated as a partnership for federal income tax purposes (the “Qualifying Income Exception”). Qualifying income includes income and gains derived from the mining, transportation and marketing of minerals and natural resources, such as coal. Other types of qualifying income include interest (other than from a financial business), dividends, gains from the sale of real property and gains from the sale or other disposition of capital assets held for the production of income that otherwise constitutes qualifying income.

We currently meet the Qualifying Income Exception and expect to continue to qualify prospectively for this exception. As such, each of our unitholders will take into account their respective share of our items of income, gain, loss and deduction in computing their federal income tax liability as if the unitholder had earned such income directly, even if we make no cash distributions to the unitholder. Distributions we make to a unitholder generally will not give rise to income or gain taxable to such unitholder, unless the amount of cash distributed exceeds the unitholder’s adjusted tax basis. 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 and the taxable income allocation requirements under our partnership agreement. Individual unitholders have different investment basis depending upon the timing and price of acquisition of their partnership units. Furthermore, each unitholder ’s tax accounting methods, which is partially dependent upon the unitholder’s tax position, differs from the accounting methods 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 is not available to us.

Our tax counsel has provided an opinion that FELP will be treated as a partnership. However, as is customary, no ruling has been or will be requested from the Internal Revenue Service (“IRS”) regarding our classification as a partnership for federal income tax purposes.

FELLC, its subsidiaries and controlled entities were established as limited liability companies, and thus for federal and, if applicable, state and local income tax purposes, are treated as pass-through entities. Therefore, no provision for income taxes was included in the consolidated financial statements.

There were no new authoritative accounting pronouncements that had a significant impact on the Partnership’s consolidated financial statements or impacted comparability with prior periods presented.

In April 2014, the Financial Accounting Standards Board (“FASB”) issued Accounting Standards Update (“ASU”) 2014-08, Reporting Discontinued Operations and Disclosures of Disposals of Components of an Entity. ASU 2014-08 changes the requirements for reporting discontinued operations by updating the criteria for determining discontinued operations and modifies the disclosure requirements of both discontinued operations and certain other disposals not defined as discontinued operations. ASU 2014-08 is effective for annual and interim periods beginning after December 15, 2014 and we do not expect it will have a material effect on our consolidated financial statements.

In May 2014, the FASB issued ASU 2014-09, Revenue from Contracts with Customers, to clarify the principles used to recognize revenue. The guidance is effective for annual and interim periods beginning after December 15, 2016. Early adoption is not permitted. We are in the process of evaluating the effects, if any, the adoption of this guidance will have on our consolidated financial statements.

In August 2014, the FASB issued ASU 2014-15, Disclosure of Uncertainties about an Entity’s Ability to Continue as a Going Concern, which requires management of the entity to evaluate whether there is substantial doubt about the entity’s ability to continue as a going concern. This ASU is effective for the annual reporting period ending after December 15, 2016, with early adoption permitted. This standard is not currently expected to have a material effect on the Partnership's financial statement disclosures, though the ultimate impact will be dependent on the Partnership's financial condition and expected operating outlook.

On June 18, 2014, the Partnership’s common units began trading on the New York Stock Exchange (“NYSE”) under the symbol “FELP.” Upon the closing of the initial public offering (“IPO”) on June 23, 2014, the following transactions occurred:

In July 2014, the underwriters’ overallotment option expired, resulting in an additional 2,625,000 units being issued, on a pro rata basis, to Foresight Reserves and a member of management for no additional consideration. The initial common units held by the public, after the issuance of these overallotment units in July 2014, represented 13.5% of the outstanding limited partnership interest.

The Partnership has commodity price risk for its coal sales as a result of changes in the market value of its coal. To minimize this risk, we enter into long-term, fixed price coal supply sales agreements and coal derivative swap contracts.

As of December 31, 2014 and 2013, we had outstanding coal derivative swap contracts to fix the selling price on 3.4 million tons and 2.0 million tons, respectively. Swaps are designed so that the Partnership receives or makes payments based on a differential between fixed and variable prices for coal. The coal derivative contracts are economic hedges to certain future unpriced (indexed) sales commitments and expected sales through 2017. The coal derivative contracts are indexed to the Argus API 2 price index, the benchmark price for coal imported into northwest Europe. The coal derivative contracts are accounted for as freestanding derivatives and any gains or losses resulting from adjusting these contracts to fair value are recorded into earnings. We record the fair value of all positions with a given counterparty on a gross basis in the consolidated balance sheets (see Note 16).

We have master netting agreements with all of our counterparties that allow for the settlement of contracts in an asset position with contracts in a liability position in the event of default. We manage counterparty risk through the utilization of investment grade commercial banks, diversification of counterparties and our counterparty netting arrangements.

The following is a summary of the unrealized and realized gains recorded on coal derivatives for the years ended December 31, 2014, 2013 and 2012:

We received $7.3 million and $1.0 million in proceeds during the years ended December 31, 2014 and 2013, respectively, from derivatives that settled prior to an economically hedged sales contract. These settlements were recorded as an investing activity in the consolidated statements of cash flows.

In August 2013, FELLC issued $600.0 million of 7.875% senior notes due August 15, 2021 (the “2021 Senior Notes”). The proceeds from the issuance were used to redeem $600.0 million of outstanding 9.625% senior notes due in 2017 (the “2017 Senior Notes”) through a tender offer. We recorded a $77.3 million loss on the early extinguishment of debt during the year ended December 31, 2013 for the $72.1 million in tender costs to redeem the 2017 Senior Notes and to write-off $5.2 million in unamortized debt issuance costs. The tender costs were recorded as an operating activity in the consolidated statement of cash flows. The 2021 Senior Notes are guaranteed on a senior unsecured basis by all of the domestic operating subsidiaries of Foresight Energy LP, other than Foresight Energy Finance Corporation, co-issuer of the notes. The interest on the 2021 Senior Notes is due semiannually on February 15 and August 15 of each year. The 2021 Senior Notes were issued at an initial discount of $4.3 million, which is being amortized using the effective interest method over the term of the notes.

Prior to August 15, 2016, we may redeem some or all of the 2021 Senior Notes at a redemption price equal to the sum of the principal amount of the 2021 Senior Notes to be redeemed, plus accrued and unpaid interest, plus the applicable make-whole premium. After August 15, 2016, we may redeem all or a part of the 2021 Senior Notes at the redemption prices (expressed as a percentage of principal) set forth below plus accrued and unpaid interest, if redeemed during the 12-month period commencing on August 15 of the years indicated below:

In August 2013, FELLC executed the second amendment to its credit agreement (the “Credit Agreement”) to increase the borrowing capacity under its senior secured revolving credit facility (the “Revolving Credit Facility”) from $400.0 million to $500.0 million and extend the maturity date to August 23, 2018. The amendment resulted in the write-off of $0.4 million in unamortized debt issuance costs due to certain lenders changing their commitment level under the credit agreement. Borrowings under the Revolving Credit Facility bear interest at a rate equal to, at the Partnership’s option, (1) British Bankers’ Association (as published by Reuters) LIBOR plus an applicable margin ranging from 2.50% to 3.50% or (2) a base rate plus an applicable margin ranging from 1.50% to 2.50%, in each case, determined in accordance with the Partnership’s consolidated net leverage ratio. The Partnership is also required to pay a 0.5% commitment fee to the lenders under the Revolving Credit Facility for unutilized commitments. The weighted-average interest rate on borrowings under the Revolving Credit Facility as of December 31, 2014 and 2013 was 3.5%. At December 31, 2014, we had $6.5 million outstanding in letters of credit and $174.0 million of remaining capacity under the Revolving Credit Facility.

Under the Credit Agreement, we are subject to customary debt covenants, including a consolidated interest coverage ratio and a consolidated senior secured leverage ratio. We were in compliance with our financial debt covenants as of December 31, 2014.

In August 2013, the Credit Agreement was also amended for the issuance of a $450.0 million senior secured term B loan (the “Term Loan”). The Term Loan was issued at an original issuance discount of $4.5 million which will be amortized over the term of the loan. In June 2014, we used proceeds from the IPO to repay $210.0 million in principal outstanding under the Term Loan. This prepayment resulted in the write-off of $2.8 million in unamortized debt issuance costs and $1.9 million of unamortized debt discount. The prepayment of principal was applied to prospective scheduled quarterly principal payments as set forth in the Credit Agreement such that no further scheduled payments are due until the Term Loan matures on August 23, 2020. The Term Loan bears interest at LIBOR plus 4.5%, subject to a 1.0% LIBOR floor. As of December 31, 2014 and 2013, the interest rate on the Term Loan was 5.5%.

In January 2010, FELLC entered into a credit agreement with a financial institution to provide financing for longwall equipment and related parts and accessories. The financing arrangement is collateralized by the longwall mine equipment. Interest accrues on the note at a fixed rate per annum of 5.78% and is due semiannually in June and December until maturity. Principal is due in 17 equal semiannual payments through June 30, 2020. The outstanding balance as of December 31, 2014 was $61.6 million. The guaranty agreement between FELLC and the lender under this financing arrangement has financial covenants that are identical to those of the Credit Agreement.

In May 2010, FELLC entered into a credit agreement with a financial institution to provide financing for longwall equipment and related parts and accessories. The financing arrangement is collateralized by the longwall mine equipment. Interest accrues on the note at a fixed rate per annum of 5.555% and is due semiannually in March and September until maturity. Principal is due in 17 equal semiannual payments through September 30, 2020. The outstanding balance as of December 31, 2014 was $61.9 million. The guaranty agreement between FELLC and the lender under this financing arrangement has financial covenants that are identical to those of the Credit Agreement.

In March 2012, FELLC entered into a finance agreement with a financial institution to fund the manufacturing of longwall equipment. Upon taking possession of the longwall equipment during the third quarter of 2012, this interim longwall finance agreement was converted into six individual leases with maturities of four and five years beginning on September 1, 2012. These leases contain a bargain purchase option at the end of the lease term and are accounted for as capital lease obligations. These capital lease obligations bear interest ranging from 5.4% to 6.3%, and principal and interest payments are due monthly over the terms of the leases. As of December 31, 2014, $30.5 million was outstanding under these capital lease obligations.

In November 2014, the Partnership entered into a sale-leaseback financing arrangement with a financial institution under which it sold a set of longwall shields and related equipment to a financial institution for $55.9 million and leased the shields back under three individual leases. We account for these leases as capital lease obligations since ownership of the longwall shields and related equipment transfer back to us upon the completion of the leases. These capital lease obligations bear interest at 5.762% and principal and interest payments are due monthly over the five-year terms of the leases. Aggregate termination payments of $2.8 million are due at the end of the lease terms. As of December 31, 2014, $55.1 million was outstanding under these capital lease obligations.

In November 2013, FELLC entered into an interim longwall financing arrangement and master lease agreement with a lender to finance the installment payments required under a contract with a vendor for the purchase of a set of longwall shields and related parts and equipment. This interim longwall financing arrangement, as amended, allowed for borrowings up to the expected purchase price of $63.2 million. In May 2014, the interim longwall financing arrangement and master lease agreement were terminated with the repayment of the $61.3 million outstanding balance. Lender fees of $0.3 million were recorded to loss on early extinguishment of debt during for the early termination of the master lease agreement.

On January 13, 2015, Foresight Energy LP and certain of its wholly-owned subsidiaries, entered into a $70.0 million receivables securitization program (the “Program”). Under this Program, our subsidiaries will sell their customer trade receivables (the “Receivables”), on a revolving basis, to Foresight Receivables LLC, a wholly-owned special purpose subsidiary of Foresight Energy LP (the “SPV”). The SPV will then pledge its interests in the Receivables to the securitization program lenders, which will either make loans or issue letters of credit to, or on behalf of, the SPV. The maximum amount of advances and letters of credit outstanding under the program may not exceed $70 million. The amount eligible for borrowing will be determined by the qualified receivable balances outstanding. The Program has a three-year maturity and will expire on January 12, 2018. The borrowings under the Program have two tranches of interest rates that approximate the one-month LIBOR rate plus 0.80%, and the Program also carries a commitment fee of 0.40% for unutilized commitments.

We used the initial $57.2 million of proceeds under the Program primarily to reduce amounts outstanding under our Revolving Credit Facility.

The following summarizes the contractual principal maturities of long-term debt (excluding unamortized aggregate discounts of $5.7 million) and capital lease obligations as of December 31, 2014:

The above table represents defined contractual repayments and does not assume any early voluntary prepayment of principal.

The aggregate amount of minimum lease payments (which includes principal and interest) for capital lease obligations is $96.4 million as of December 31, 2014. Minimum lease payments from 2015 through 2019 are as follows:

In January 2009, Macoupin entered into a sales agreement with WPP, LLC (“WPP”) and HOD, LLC (“HOD”) (subsidiaries of Natural Resource Partners LP (“NRP”)) to sell certain mineral reserves and rail facility assets (the “Macoupin Sales Arrangement”). NRP is an affiliate of the Partnership (see Note 14). Macoupin received $143.5 million in cash in exchange for certain mineral reserve and transportation assets. Simultaneous with the closing, Macoupin entered into a lease with WPP for mining the mineral reserves (the “Mineral Reserves Lease”) and with HOD for the use of the rail loadout and rail loop (the “Macoupin Rail Loadout Lease” and the “Rail Loop Lease,” respectively). The Mineral Reserves Lease is a 20-year noncancelable lease that contains renewal elections for six additional five-year terms. The Macoupin Rail Loadout Lease and the Rail Loop Lease are 99 year noncancelable leases. Under the Mineral Reserves Lease, Macoupin makes monthly payments equal to the greater of $5.40 per ton or 8.00% of the sales price, plus $0.60 per ton for each ton of coal sold from the leased mineral reserves, subject to a minimum royalty of $4.0 million per quarter through December 31, 2028. After the initial 20-year term, the annual minimum royalty is $10,000 per year. The minimum royalty is recoupable on future tons mined. If during any quarter the tonnage royalty under the Mineral Reserves Lease and tonnage fees paid under the Macoupin Rail Loadout and Rail Loop Leases discussed below exceed $4.0 million, Macoupin may generally recoup any unrecouped quarterly payments made during the preceding 20 quarters on a first paid, first recouped basis. The Macoupin Rail Loadout Lease and Rail Loop Lease require an aggregate payment of $3.00 ($1.50 for the rail loop facility and $1.50 for the rail load-out facility) for each ton of coal loaded through the facility for the first 30 years, up to 3.4 million tons per year. After the initial 30-year term, Macoupin would pay an annual rental payment of $20,000 per year for usage of the rail loadout and rail loop. The Macoupin Sales Arrangement, Mineral Reserves Lease, Macoupin Rail Loadout Lease and Rail Loop Lease are collectively accounted for as a financing arrangement (the “Macoupin Sale-Leaseback”). This financing arrangement is recourse to Macoupin and not recourse to Foresight Energy LP or any of its other subsidiaries.

At December 31, 2014 and 2013, the amount outstanding under the Macoupin Sale-Leaseback was $143.5 million. The effective interest rate on the financing obligation was 13.9% and 14.2% as of December 31, 2014 and 2013, respectively. Interest expense was $16.3 million, $19.6 million and $20.6 million for the years ended December 31, 2014, 2013 and 2012, respectively. As of December 31, 2014 and 2013, interest of $3.0 million and $6.8 million, respectively, was accrued in the consolidated balance sheets for the Macoupin Sale-Leaseback.

In March 2012, Sugar Camp entered into a sales agreement with HOD for which it received a total of $50.0 million in cash in exchange for certain rail loadout assets (“Sugar Camp Sales Agreement”). Simultaneous with the closing, Sugar Camp entered into a lease transaction with HOD for the use of the rail loadout (the “Sugar Camp Rail Loadout Lease”). The Sugar Camp Rail Loadout Lease is a 20-year noncancelable lease that contains renewal elections for 16 additional five-year terms. Under the Sugar Camp Rail Loadout Lease, Sugar Camp will pay a monthly royalty of $1.10 per ton for every ton of coal mined from specified reserves and loaded through the rail loadout. The royalty is subject to adjustment based on the time it takes for Sugar Camp to complete each longwall move. The royalty payments are subject to a minimum payment amount of $1.3 million per quarter for the first twenty years the lease is in effect. After the initial 20-year term, Sugar Camp would pay an annual rental payment of $10,000 per year. To the extent the minimum payment exceeds amounts owed based on actual coal loaded, the excess is recoupable within two years of payment.

The Sugar Camp Sales Agreement and Sugar Camp Rail Loadout Lease are collectively accounted for as a financing arrangement (the “Sugar Camp Sale-Leaseback”). This financing arrangement is recourse to Sugar Camp and Foresight Energy LP has a limited declining commercial guaranty which began at $15 million and decreases with each minimum payment made by Sugar Camp. At December 31, 2014 and 2013, the amount outstanding under the Sugar Camp Sale-Leaseback was $50.0 million. The effective interest rate on the financing, which is derived from the timing and tons of coal to be mined as set forth in the current mine plan and the related cash payments, was 13.9% and 14.3% at December 31, 2014 and 2013, respectively. Interest expense recorded on the Sugar Camp Sale-Leaseback was $6.4 million, $7.2 million and $5.4 million for the years ended December 31, 2014, 2013 and 2012, respectively. As of December 31, 2014 and 2013, interest of $2.5 million and $2.3 million, respectively, was accrued in the consolidated balance sheets for the Sugar Camp Sale-Leaseback.

In August 2013, an agreement was reached between the Partnership, Foresight Reserves and HOD that allows for the existing Sugar Camp Rail Loadout Lease to be amended in the future to include coal produced from the second longwall at Sugar Camp on what is expected to be materially consistent terms as the original agreement discussed. Pursuant to such an amendment occurring, the consideration paid by HOD for including coal produced by the second longwall at Sugar Camp will be paid directly to Foresight Reserves.

The following summarizes the maturities of expected principal payments, based on current mine plans, on the Partnership’s sale-leaseback financing arrangements, and accrued interest at December 31, 2014:

The aggregate amounts of remaining minimum lease payments on the Partnership’s sale-leaseback financing arrangements are $310.3 million. Minimum payments from 2015 through 2019 are as follows:

The Partnership leases certain surface rights, mineral reserves, mining, transportation and other equipment under various lease agreements with related entities under common control, other affiliated entities and independent third parties in the normal course of business.

The mineral reserve leases can generally be renewed as long as the mineral reserves are being developed and mined until all economically recoverable reserves are depleted or until mining operations cease. The lease agreements typically require a production royalty at the greater amount of a base amount per ton or a percent of the gross selling price of the coal. Generally, the leases contain provisions that require the payment of minimum royalties regardless of the volume of coal produced or the level of mining activity. The minimum royalties are generally recoupable against production royalties over a contractually defined period of time (typically five to ten years). Some of these agreements also require overriding royalty and/or wheelage payments. Under the terms of certain mineral reserve leases, the Partnership is to use commercially reasonable efforts to acquire additional mineral reserves in certain properties as defined in the agreements and is responsible for the acquisition costs and the assets are to be titled to the lessor. Transportation throughput agreements generally require a per ton fee amount for coal transported and contain certain escalation clauses and/or renegotiation clauses. For certain transportation assets, the Partnership is responsible for operations, repairs, and maintenance and for keeping the transportation facilities in good working order. Surface rights, mining, and other equipment leases require monthly payments based upon the specified agreements. Certain of these leases provide options for the purchase of the property at various times during the life of the lease, generally at its then-fair market value. The Partnership also leases certain office space, rail cars and equipment under leases with varying expiration dates.

The following presents future minimum payments, by year, required under contractual royalty and throughput arrangements with related entities and third parties as of December 31, 2014:

The following presents future minimum lease payments, by year, required under noncancelable operating leases with initial terms greater than one year, as of December 31, 2014:

Total rental expense from operating leases for the years ended December 31, 2014, 2013, and 2012 was $16.1 million, $17.0 million, and $17.2 million, respectively. Included in rental expense is $9.9 million, $9.9 million, and $11.5 million for the years ended December 31, 2014, 2013 and 2012, respectively, of contingent rental payments to Williamson Transport, a subsidiary of NRP, for the rail loadout facility at Williamson Energy. We pay contingent rental fees, net of a fixed per ton amount received for maintaining the facility, on each ton of coal passed through the rail loadout facility.

The change in the carrying amount of asset retirement obligations was as follows:

The credit-adjusted, risk-free interest rates used in determining the asset retirement obligations were 6.6%, 8.8% and 7.6% at December 31, 2014, 2013, and 2012, respectively.

Certain of our consolidated affiliates are responsible under Illinois statutes and the Federal Coal Mine Health and Safety Act of 1969, as amended, for medical and disability benefits to employees and their dependents resulting from occurrences of coal workers’ pneumoconiosis disease (“CWP”). In addition, state statutes dictate that we provide income replacement and medical treatment for work-related traumatic injury claims, including survivor benefits for employment related deaths. Effective July1, 2014, we terminated our guaranteed cost program in favor of a high deductible insurance program.

Our liability for CWP benefits was estimated by an independent actuary based on assumptions regarding medical costs, allocated loss adjustment expense, claim development patterns and interest rates. For the year ended December 31, 2014, we recorded CWP expense of $1.5 million and have a CWP liability of $1.5 million recorded in other long-term liabilities in the consolidated balance sheet as of December 31, 2014.

Our liability for workers compensation benefits was determined by a third-party administrator based on actual claims incurred and the expected development of those claims. For the year ended December 31, 2014, we recorded workers’ compensation expense of $1.4 million and have a workers’ compensation liability of $1.1 million recorded in accrued expenses and other current liabilities in the consolidated balance sheet.

The chairman of our general partner’s board of directors and the controlling member of Foresight Reserves, Chris Cline, directly and indirectly beneficially owns a 31% and 4% interest in the general and limited partner interests of NRP, respectively. We routinely engage in transactions in the normal course of business with NRP and its subsidiaries and Foresight Reserves and its affiliates. These transactions include production royalties, transportation services, administrative arrangements, coal handling and storage services, supply agreements, service agreements, land leases and sale-leaseback financing arrangements (see Note 10, sale-leaseback financing arrangements are excluded from the discussion and tables below). We also acquire, from time to time, mining equipment from Foresight Reserves and affiliated entities.

The Partnership’s general partner manages the Partnership’s operations and activities as specified in the partnership agreement. The general partner of the Partnership is managed by its board of directors. Foresight Reserves has the right to select the directors of the general partner. The members of the board of directors of the general partner are not elected by the unitholders and are not subject to reelection by the unitholders. The officers of the general partner manage the day-to-day affairs of the Partnership’s business. The partnership agreement provides that the Partnership will reimburse its general partner for all direct and indirect expenses incurred or payments made by the general partner on behalf of the Partnership. No amounts were incurred by the general partner or reimbursed under the partnership agreement from the IPO date to December 31, 2014.

Our mines have a series of mineral reserve leases with Colt, LLC (“Colt”) and Ruger, LLC (“Ruger”), subsidiaries of Foresight Reserves. Each of these leases have initial terms of 10 years with six renewal periods of five years each, at the election of the lessees, and generally require the lessees to pay the greater of $3.40 per ton or 8.5% of the gross sales price, as defined in the respective agreements, of such coal. We also have overriding royalty agreements with Ruger pursuant to which we pay royalties equal to 8.0% of the gross selling prices, as defined in the agreements. Each of these mineral reserve leases generally require a minimum annual royalty payment, which is recoupable only against actual production royalties from future tons mined during the period of 10 years following the date on which any such royalty is paid.

We also lease mineral reserves under lease agreements with subsidiaries of NRP, including WPP, HOD, and Independence Energy, LLC (“Independence”). The initial terms of these agreements vary, however, each carries an option by the lessee to extend the leases until all merchantable and mineable coal has been mined and removed. Royalty payments under these arrangements are generally determined based on the greater of a minimum per ton amount (ranging from $2.50 per ton to $5.40 per ton) or a percentage of the gross sales price (generally 8.0% - 9.0%), as defined in the respective agreements. We are also subject under certain of these mineral reserve agreements to overriding royalties and/or wheelage fees. Our mineral reserve leases with NRP subsidiaries also require minimum quarterly or annual royalties which are generally recoupable on future tons mined and sold during the preceding five-year period from the excess tonnage royalty payments on a first paid, first recouped basis.

As of December 31, 2014, we have established a $34.7 million reserve against a contractual prepaid royalty between Hillsboro and WPP given that the recoupment of certain prior minimum royalty payments was improbable given the remaining recoupment period available and forecasted demand for Hillsboro coal based on current and forecasted near-term market conditions. We continually evaluate our ability to recoup prepaid royalty balances which includes, among other things, assessing mine production plans, sales commitments, current and forecasted future coal market conditions, and remaining years available for recoupment.

In connection with the 2013 Reorganization (see Note 17), each of our mines entered into a transloading and storage agreement with Sitran, a barge transloading facility on the Ohio River owned by Foresight Reserves. These agreements provide for the unloading of coal from railcars into stockpiles at Sitran and for the loading of coal from stockpiles into barges. Under these agreements each mine pays Sitran a fee for each ton of coal offloaded, stored or transloaded at Sitran’s facility. The agreements carry no minimum volume requirements. Each agreement has an initial term of three years and automatically renew for successive one-year periods unless terminated by either party. On February 25, 2015, Foresight Reserves and a member of management contributed Sitran to the Partnership (see Note 17).

In August 2011, an affiliated company owned by Foresight Reserves acquired the IC RailMarine Terminal in Convent, Louisiana. This terminal, commonly referred to as the Convent Marine Terminal (“CMT”), is owned by Raven Energy LLC, an entity controlled and beneficially owned by Christopher Cline. The terminal is designed to ship and receive commodities via rail, river barge and ocean vessel. We have a contract for throughput at the terminal that continues through December 31, 2021 under which we pay fees based on the tonnages of coal we move through the terminal, subject to minimum annual take-or-pay volume commitments.

In August 2013, FELLC entered into an equipment repair and rebuild agreement with Seneca Rebuild LLC (“Seneca Rebuild”), an affiliated entity owned indirectly by Chris Cline. The agreement called for Seneca Rebuild to be the primary provider of repair and rebuild services for mining machinery and equipment for our mines. Effective April 1, 2014, FELLC reached an agreement to acquire Seneca Rebuild for $3.8 million, net of cash acquired. Because FELLC and Seneca Rebuild were under common control, the assets and liabilities of Seneca Rebuild were recorded by FELLC at carrying value on the acquisition date. Seneca Rebuild’s net assets on the acquisition date consisted principally of property, plant and equipment. The $0.3 million paid over the excess of the carrying value of

the net assets of Seneca Rebuild on the acquisition date was recorded as a deemed distribution. Given the immateriality of this acquisition, the financial results of Seneca Rebuild are reflected prospectively in the consolidated financial statements of the Partnership.

Williamson leases property from Williamson Transport, an affiliate of NRP, under two surface leases with initial terms through October 15, 2031 and an option to extend the leases in five-year increments until all the coal leased from an NRP affiliate is mined on Williamson’s premises. Williamson Transport has the option to put the land to Williamson for its fair market value as determined by an independent appraiser at any time during the lease term. Additionally, under a separate lease with an initial term through March 12, 2018, Williamson pays $5,000 per year for use of the premises and a fee, currently at $1.80 per ton, for each ton of coal produced at Williamson that is loaded through the Williamson rail loadout facility. Williamson Transport may elect to renew or extend the sublease for successive five-year periods. If Williamson Transport elects not to renew the sublease, Williamson has the option to buy the Williamson rail loadout facility for its fair market value as determined by an independent appraiser. Williamson receives a fee of $0.25 per ton from Williamson Transport for each ton of coal that is loaded through the Williamson rail loadout facility in exchange for operating the load out.

We are party to two surface leases in relation to the coal preparation plant and rail loadout facility at Williamson with New River Royalty, a subsidiary of Foresight Reserves. The primary terms of the leases expire on October 15, 2021, but may be extended by New River Royalty for additional five-year terms under the same terms and conditions until all of the merchantable and mineable coal has been mined and removed from Williamson. Williamson is required to pay aggregate rent of $100,000 per year to New River Royalty under the leases. Additionally, New River Royalty may require Williamson to purchase any portion of either of the leased properties at any time while the leases are in effect for $3,000 an acre. Williamson Transport has the option to purchase any property optioned under the leases if Williamson does not perform its purchase obligation within fifteen days of receiving notice of its purchase obligation.

We may arrange air travel on an individual flight basis with affiliated entities controlled by Chris Cline. These expenses are incurred hourly (at estimated cost), by flight, and are initially paid by the affiliated entities and then reimbursed by us. We also from time to time utilize other assets controlled by Chris Cline and reimburse the affiliated entities on a time-incurred basis.

In January 2007, Chris Cline, Foresight Reserves, Adena Minerals LLC and their respective affiliates (collectively, “Adena Entities”) and NRP executed a restricted business contribution agreement. The restricted business contribution agreement obligates the Adena Entities and their affiliates to offer NRP any business owned, operated or invested in by the Adena Entities, subject to certain exceptions, that either (a) owns, leases or invests in hard minerals or (b) owns, operates, leases or invests in identified transportation infrastructure relating to certain future mine developments by the Adena Entities in Illinois. NRP’s acquisition of certain coal reserves and infrastructure assets related to our Macoupin, Hillsboro and Sugar Camp mining complexes, discussed above and in Note 10, were deals consummated under the restricted business contribution agreement with the Adena Entities. The Adena Entities are required to offer and could consummate additional deals under the restricted business contribution agreement in the future.

During the years ended December 31, 2014 and 2013, we purchased $18.1 million and $14.7 million in mining supplies from an affiliated joint venture under a supply agreement entered into in May 2013 (see Note 15).

We receive monthly fees from Foresight Reserves in exchange for performing bookkeeping and other administrative functions for certain of its subsidiaries.

The following table presents the affiliate amounts included in our consolidated balance sheets:

(1) – Prepaid royalties with NRP and affiliated entities is presented net of a $34,700 reserve.

A summary of expenses (income) incurred with affiliated entities is as follows for the years ended December 31, 2014, 2013 and 2012:

(1) – Cost of coal produced (excluding depreciation, depletion and amortization)

The contractual commitment tables for operating leases, transportation throughput agreements, and royalty agreements with affiliated parties are disclosed in Note 11.

The consolidated financial statements include VIEs for which the Partnership or its subsidiary is the primary beneficiary. Among those VIEs consolidated by the Partnership and its subsidiaries are Mach Mining, LLC; M-Class Mining, LLC; MaRyan Mining LLC; Patton Mining LLC; Viking Mining LLC, Coal Field Construction Company LLC; Coal Field Repair Services LLC and LD Labor Company LLC (prior to the 2013 Reorganization date discussed below) (collectively, the “Contractor VIEs”). Each of the Contractor VIEs holds a contract to provide one or more of the following services to a Partnership subsidiary: contract mining, processing and loading services, or construction and maintenance services. Each of the Contractor VIEs generally receives a nominal per ton fee ($0.01 to $0.02 per ton) above its cost of operations as compensation for services performed. All of these entities were determined not to have sufficient equity at risk and are therefore VIEs. The Partnership was determined to be the primary beneficiary of each of these entities given it controls these entities under a contractual cost-plus arrangement. During the years ended December 31, 2014, 2013 and 2012, in aggregate, the Contractor VIEs earned income of $0.4 million, $0.3 million and $0.2 million, respectively, under the

contractual arrangements with the Partnership which was recorded as net income attributable to noncontrolling interests in the consolidated statements of operations.

On August 23, 2013, FELLC effected a reorganization pursuant to which certain transportation assets were distributed to its members (see Note 17). Among the assets distributed were Adena Resources LLC (“Adena”), a subsidiary that provides water and other miscellaneous rights to the mines and Hillsboro’s coal loadout facility, including the land on which the facility is situated (collectively, the “Loadout”).

Adena has various water rights contracts that are used to provide water to the Partnership’s mines. Concurrent with the distribution of Adena to FELLC members, we entered into a water resources agreement between the Partnership’s mines and Adena providing for water resources to be available at each of the mines. As compensation for furnishing water to the mines, we pay Adena the actual cost (including capital expenditures) incurred by Adena plus an annual fee of $10,000. Adena is determined not to have sufficient equity at risk and is therefore a VIE. The Partnership is determined to be the primary beneficiary of Adena given it controls this entity under a contractual cost-plus arrangement. During the years ended December 31, 2014 and 2013, Adena incurred a loss of $0.4 million and $0.2 million, respectively, which was recorded as net income attributable to noncontrolling interests in the consolidated statements of operations. On February 25, 2015, Foresight Reserves and a member of management contributed Adena to the Partnership (see Note 17).

Subsequent to the 2013 Reorganization, Foresight Reserves placed the Loadout into a newly created subsidiary, Hillsboro Transport, LLC (“Hillsboro Transport”). A throughput agreement was entered into between Hillsboro and Hillsboro Transport for Hillsboro Transport to operate the Loadout. As compensation for operating and maintaining the Loadout, Hillsboro pays $0.99 per ton for every ton of coal loaded through the Loadout, subject to a minimum quarterly payment of $1.3 million, which began in the first quarter of 2014. Hillsboro Transport was determined not to have sufficient equity at risk as a result of the throughput agreement’s guaranteed minimum quarterly payment and is therefore a VIE. Hillsboro was determined to be the primary beneficiary of this entity as it implicitly controls Hillsboro Transport given the related-party relationship between Hillsboro and Hillsboro Transport and the fact that the sole assets held by Hillsboro Transport are unique to Hillsboro’s operations. During the years ended December 31, 2014 and 2013, Hillsboro Transport earned $3.8 million and $2.0 million, respectively, in net income under this arrangement, which is presented in net income attributable to noncontrolling interests in the consolidated statements of operations. On February 25, 2015, Foresight Reserves and a member of management contributed Hillsboro Transport to the Partnership (see Note 17).

The liabilities recognized as a result of consolidating the VIEs do not necessarily represent additional claims on the general assets of the Partnership outside of the VIEs; rather, they represent claims against the specific assets of the consolidated VIEs. Conversely, assets recognized as a result of consolidating these VIEs do not necessarily represent additional assets that could be used to satisfy claims against the Partnership’s general assets. There are no restrictions on the VIE assets that are reported in the Partnership’s general assets. The total consolidated VIE assets and liabilities reflected in the Partnership’s consolidated balance sheets are as follows:

In May 2013, an affiliate owned by Chris Cline and a third-party supplier of mining supplies formed a joint venture whose purpose is the manufacture and sale of supplies primarily for use by the Partnership in the conduct of its mining operations. The agreement obligates the Partnership’s coal mines to purchase at least 90% of their aggregate annual requirements for certain mining supplies from the supplier parties, subject to exceptions as set forth in the agreement. The initial term of the amended agreement is five years and expires in April 2018. The supplies sold under this arrangement result in an agreed-upon fixed profit percentage for the joint venture. This joint venture was determined to be a VIE given that the equity holders do not have the obligation to absorb the expected losses or the right to receive the expected residual returns of the joint venture as a result of the Partnership effectively guaranteeing a fixed-profit percentage on the supplies it purchases from the joint venture. We are not the primary beneficiary of this joint venture

and, therefore, do not consolidate the joint venture, given that the power over the joint venture is conveyed through the board of directors of the joint venture and no party controls the board of directors.

The tables below set forth, by level, the Partnership’s net financial assets and liabilities for which fair value is measured on a recurring basis:

The Partnership’s coal derivative contracts are valued based on direct broker quotes and corroborated with API 2 market pricing data. The liability award represents a phantom equity award (“Liability Award”) to a retired executive for which the value was determined based on the fair value, as defined in the agreement, of Foresight Reserves as of the employee’s retirement date and was adjusted for distributions made to Foresight Reserves’ members. This Liability Award fully vested in 2010 and was granted principally for services performed to develop the Partnership’s longwall mines. Prior to March 31, 2014, the Liability Award was Level 3 in the fair value hierarchy given Foresight Reserves was a private company; therefore, there was no liquid market to determine the fair value of Foresight Reserves’ equity. The fair value of the Liability Award was determined using a discounted cash flow model and corroborated with recent equity transactions at Foresight Reserves. Effective March 31, 2014, the Liability Award amount was negotiated between the Partnership and the employee to be $12.4 million; therefore, the value of this liability was contracted and therefore no longer a Level 3 liability. As of December 31, 2014, $0.4 million of the unpaid balance is recorded in accrued expenses and other current liabilities for required payments over the next year, and the remaining $3.8 million is recorded in other long-term liabilities, which will be paid out ratably through 2024. The note payable to the retired executive currently bears interest at 3.45%.

The classification and amount of the Partnership’s financial instruments measured at fair value on a recurring basis, which are presented on a gross basis in the consolidated balance sheets as of December 31, 2014 and 2013, are as follows:

The following is a reconciliation of the beginning and ending balances for assets and liabilities measured at fair value on a recurring basis using significant unobservable inputs (Level 3) during the years ended December 31, 2014 and 2013:

During the years ended December 31, 2014, 2013 and 2012, there were no assets or liabilities that were transferred between Level 1 and Level 2.

The fair value of long-term debt as of December 31, 2014 and 2013 was $1,279.7 million and $1,509.2 million, respectively. The fair value of long-term debt was calculated based on the amount of future cash flows associated with each debt instrument discounted at the Partnership’s current estimated credit-adjusted borrowing rate for similar debt instruments with comparable terms. This is considered a Level 3 fair value measurement.

Our partnership agreement contains provisions for the allocation of net income and loss to the unitholders and the general partner. For purposes of maintaining partner capital accounts, the partnership agreement generally specifies that items of income and loss shall be allocated among the partners in accordance with their respective percentage interest.

The percentage interests set forth below assumes there are no arrearages on common units.

Our partnership agreement sets forth the calculation to be used to determine the amount and priority of cash distributions that the common and subordinated unitholders and general partner will receive.

In August and November of 2014, we declared and paid quarterly cash distributions of $0.03 per unit (equal to the MQD, rounded-up, and prorated for the period from the closing date of the IPO to the end of the second quarter) and $0.35 per unit, respectively, to all unitholders on the respective record dates.

On February 6, 2015, we declared a quarterly cash distribution of $0.36 per unit to all unitholders, which was paid on February 27, 2015, to all unitholders of record on February 16, 2015.

Simultaneously with the closing of the debt refinancing on August 23, 2013 (see Note 9), FELLC underwent a reorganization (the “2013 Reorganization”) pursuant to which it distributed to its members 100% of its ownership interest in Sitran, Adena and Hillsboro Transport. FELLC recorded a non-cash distribution totaling $62.0 million in August 2013 to reflect these distributions to its members. In May 2014, based upon the terms of the 2013 Reorganization, FELLC distributed to its members approximately 1,900 acres of surface land not needed for current or currently projected future operations and $0.1 million in cash. The carrying value of the distributed land was $12.2 million. Additionally, in connection with the acquisition of Seneca Rebuild on April 1, 2014, a deemed distribution in the amount of $0.3 million was recorded to reflect the excess of the purchase price paid by FELLC over the carrying value of the net assets acquired (see Note 14).

On June 23, 2014, in connection with the IPO, Foresight Reserves and a member of management each contributed their membership interests in FELLC to the Partnership in exchange for common and subordinated units of FELP (see Note 3). As a result, the members’ deficit balance of $104.9 million at the time of the transfer was allocated, pro rata based on units outstanding, to common and subordinated unitholder capital accounts.

Noncontrolling interests’ equity and net income attributable to noncontrolling interests result from the consolidation of variable interest entities for which the Partnership has no equity interests (see Note 15).

consideration. Sitran, Adena and Hillsboro Transport had an aggregate net book value of approximately $60 million at January 31, 2015.

Upon the closing of our IPO, the Partnership adopted a Long-Term Incentive Plan ("LTIP") for employees, directors, officers and certain key third-parties (collectively, the "Participants"). The Plan allows for the issuance of equity-based compensation in the form of phantom units, unit awards, unit options, unit appreciation rights, restricted units, other unit-based awards, distribution equivalent rights, performance awards, and substitute awards to Participants. The LTIP awards granted thus far are phantom units, which upon satisfaction of vesting requirements, entitle the LTIP participant to receive FELP common units. The Board of Directors of the Partnership authorized 7.0 million common units to be granted under the LTIP, with 6.2 million units available for grant as of December 31, 2014. Annual grant levels and vesting requirements are recommended by the Partnership's chief executive officer, subject to the review and approval by the board of directors.

In June 2014, upon the closing of the IPO, pre-existing cash-based compensation liability awards were converted to equity awards which are to be settled in FELP common units after meeting certain vesting requirements. As a result, on June 23, 2014, $0.6 million was reclassified from accrued expenses and other current liabilities to partners' capital for the conversion of the pre-existing cash-based awards to 154,027 phantom units to be issued under the LTIP. No additional compensation expense was recorded as a result of the modification of these awards. These modified awards are time-based unit awards and generally vest, subject to continued employment, ratably over three-year periods from the award date (with accelerated vesting in certain instances). Compensation expense for these awards is recognized on a straight-line basis over the requisite service period, net of estimated forfeitures. Upon vesting, the Partnership issues authorized and unissued shares of the Partnership's common units to the recipient. In December 2014, vesting requirements had been satisfied on certain of the awards resulting in 45,736 unrestricted common units being issued (the remaining 27,926 units were settled in cash to satisfy the individual minimum tax obligations of the Participants). As of December 31, 2014, none of the awards had been forfeited.

In June 2014, the Partnership also granted 595,075 phantom units to employees under the LTIP, of which 72,500 units vested immediately. As a result of the immediate vesting, 46,681 unrestricted common units were issued (the remaining 25,819 units were settled in cash to satisfy the individual statutory minimum tax obligations of the Participants). The remaining awards are considered time-based unit awards and generally cliff-vest, subject to continued employment, at the end of three years of service (with accelerated vesting under certain instances). Compensation expense for these awards is recognized on a straight-line basis over the requisite service period, net of estimated forfeitures. Upon vesting, the Partnership will issue authorized and unissued shares of the Partnership’s common units to the recipient. As of December 31, 2014, 9,750 units had been forfeited.

On February 5, 2015, the board of directors approved equity grants to the Partnership’s chief executive officer consisting of 215,954 common units and 215,796 subordinated units under the LTIP. The awards are fully-vested as of the grant date, but are subject to certain sale and transfer restrictions through December 31, 2019.

Also in 2014, the Partnership granted 7,919 phantom units to non-employee directors under the LTIP. These awards are considered time-based unit awards and vest ratably over a three-year period (with accelerated vesting in certain instances). Compensation expense for these awards is recognized on a straight-line basis over the requisite service period. As of December 31, 2014, none of the director awards had vested or been forfeited.

For the year ended December 31, 2014, our equity-based compensation expense was $5.0 million, net of estimated forfeitures, of which $0.3 million was capitalized. Approximately 63% of the Partnership's equity-based compensation is reported through selling, general and administrative expenses in the consolidated statement of operations with the remaining 37% recorded through cost of coal sales. As of December 31, 2014, the total unrecognized compensation expense for phantom unit awards that are expected to vest was $9.0 million. This expense is expected to be recognized over a weighted-average period of 2.3 years. The intrinsic value of the non-vested LTIP awards was $10.1 million as of December 31, 2014. All non-vested phantom units include tandem distribution incentive rights, which provide for the right to accrue quarterly cash distributions in an amount equal to the cash distributions the Partnership makes to unitholders during the vesting period and will be settled in cash upon vesting. The Partnership has approximately $0.2 million accrued for this liability as of December 31, 2014. Any distributions accrued to a Participants’ account will be forfeited if the related phantom award fails to vest according to the relevant vesting conditions.

A summary of LTIP award activity for the year ended December 31, 2014 is as follows:

Limited partners’ interest in net income attributable to the Partnership and basic and diluted earnings per unit reflect net income attributable to the Partnership from the June 23, 2014 closing date of the IPO through December 31, 2014. We compute earnings per unit (“EPU”) using the two-class method for master limited partnerships as prescribed in Accounting Standards Codification (“ASC”) 260, Earnings Per Share. The two-class method requires that securities that meet the definition of a participating security be considered for inclusion in the computation of basic EPU. In addition to the common and subordinated units, we have also identified the general partner interest and IDRs as participating securities. Under the two-class method, EPU is calculated as if all of the earnings for the period were distributed under the terms of the partnership agreement, regardless of whether the general partner has discretion over the amount of distributions to be made in any particular period, whether those earnings would actually be distributed during a particular period from an economic or practical perspective, or whether the general partner has other legal or contractual limitations on its ability to pay distributions that would prevent it from distributing all of the earnings for a particular period.

The Partnership’s net income is allocated to the limited partners, including the holders of the subordinated units, in accordance with their respective ownership percentages, after giving effect to any special income or expense allocations and incentive distributions paid to the general partner, if any. The partnership agreement contractually limits distributions to available cash as determined by our general partner; therefore, undistributed earnings of the Partnership are not allocated to the IDR holder. There were no allocations of earnings to participating securities during the periods presented below. Basic EPU is computed by dividing net earnings attributable to unitholders by the weighted-average number of units outstanding during each period. However, because our IPO was completed on June 23, 2014, the units outstanding from the IPO date are utilized for the period presented. Basic common units outstanding includes the 2,625,000 overallotment units offered to the underwriters, which were issued to Foresight Reserves and a member of management in July 2014, as of the IPO date. Diluted EPU reflects the potential dilution of common equivalent units that could occur if equity participation units are converted into common units.

The following table illustrates the Partnership’s calculation of net income per common and subordinated unit for the period indicated:

The Partnership determines creditworthiness for trade customers based on an evaluation of the customer’s financial condition. Credit losses have historically been minimal. The aggregate outstanding trade receivable balance as of December 31, 2014 from customers representing greater than 10% of our total sales was $20.4 million.

For the years ended December 31, 2014, 2013 and 2012, the following customers exceeded 10% of total coal sales:

During the years ended December 31, 2014, 2013 and 2012, export tons (inclusive of tons sold from mines under development) represented 30%, 33% and 44% of tons sold, respectively. Tons exported into Europe during the years ended December 31, 2014, 2013 and 2012 represented approximately 26%, 23% and 28%, respectively, of total tons sold during those years (inclusive of tons sold from mines under development). No other international geographic regions exceeded 10% of tons sold during the years ended December 31, 2014, 2013 and 2012. Our domestic coal sales are principally to electric utility companies in the eastern United States with installed pollution control devices.

The Partnership depends on rail, barge, and export terminal systems to deliver coal to its customers. Disruption of these services due to weather-related problems, mechanical difficulties, strikes, lockouts, bottlenecks, and other events could temporarily impair the Partnership’s ability to supply coal to its customers, resulting in decreased shipments. As such, the Partnership has sought to diversify transportation options and has entered into long-term contracts with transportation providers to ensure transportation is available to transport its coal.

In January 2014, the Illinois Environmental Protection Agency (the “IEPA”) issued Sugar Camp a violation notice regarding construction of an underground injection well without issuance of an appropriate permit (“January Notice”). Sugar Camp is working with the IEPA to finalize its permit application, which has been in process since May 2013. The IEPA has determined not to enter into a compliance commitment agreement with respect to the January Notice and has provided notice to Sugar Camp that the January Notice will be referred to the Illinois Attorney General for enforcement. While Sugar Camp believes this referral may result in the assessment of a penalty of an amount yet to be determined, there can be no assurances that an acceptable agreement will be reached. Failure to reach a satisfactory agreement with the Illinois Attorney General with respect to the January Notice could result in the assessment of fines or penalties or a suspension of injecting underground at the affected operations until a final resolution is obtained.

Sugar Camp is working to implement a sustainable solution for the future disposal of water at the mine in compliance with its permits. Sugar Camp expects to incur capital expenditures of approximately $33.0 million, $32.7 million of which has been expended through December 31, 2014.

In November 2012, six citizens filed requests for administrative review of Revision No. 1 to Permit No. 399 for the Hillsboro mine. Revision No. 1 allowed for conversion of the currently permitted coal refuse disposal facility from a non-impounding to an impounding structure. Shortly after the filing of Revision No. 1, one citizen withdrew his request. Following a hearing on both the Illinois Department of Natural Resources’ (IDNR) and Hillsboro’s motions to dismiss, the hearing officer dismissed the claims of two of the remaining five petitioners and also limited some of the issues remaining for administrative review. In June 2014, two of the remaining three petitioners voluntarily dismissed their requests. A hearing is scheduled for spring 2015 to address all legal issues raised by the remaining petitioner.

FELLC acquired the Shay No. 1 Mine at Macoupin (“Shay Mine”) in 2009. Prior to this acquisition, in 2003, ExxonMobil Coal USA, Inc. (“Exxon”), the prior owner of the Shay Mine, enrolled the mine in the IEPA’s Site Remediation Program (“SRP”) to address some concerns regarding groundwater contamination from the refuse areas. In 2011, Macoupin proposed, and the IEPA accepted, a compliance commitment agreement (“CCA”) with remediation steps designed to respond to the groundwater contamination concerns. Further, in May 2013, Macoupin submitted a corrective action plan (“CAP”) with groundwater modeling to the IEPA to address the long-term compliance and corrective measures planned for the cleanup of groundwater contamination issues. In June 2013, the IEPA referred the CCA to the Illinois Attorney General’s Office for enforcement on the basis that the compliance period for the CCA extended for too long of a period for the IEPA to monitor. The CAP has been approved by the IEPA and Macoupin reached an agreement in principle with the Illinois Attorney General which, upon finalization of a consent decree, will result in the CAP being implemented. As of December 31, 2014, the Partnership had accrued $6.9 million for this matter as an asset retirement obligation, as it relates to ongoing mining operations at Macoupin. However, there can be no assurance that the ultimate costs will not exceed this amount.

In addition, in 2013, the IDNR renewed a permit for the Macoupin refuse disposal area. An environmental group has submitted a Request for Administrative Review of this permit renewal and the legal proceeding is ongoing. While the Partnership believes the IDNR decisions on the issuance of the permit for slurry disposal and renewal for existing refuse disposal area were proper, there can be no guarantee that the permit and the revisions to permits will not be vacated or substantially modified, which could result in additional costs or cessation of some or all operations at the mine.

We are also party to various other litigation matters, in most cases involving ordinary and routine claims incidental to our business. We cannot reasonably estimate the ultimate legal and financial liability with respect to all pending litigation matters. However, we believe, based on our examination of such matters, that the ultimate liability will not have a material adverse effect on our financial position, results of operations or cash flows. As of December 31, 2014, we have $1.2 million accrued, in aggregate, for various litigation matters.

We had outstanding surety bonds with third parties of approximately $54.8 million as of December 31, 2014 to secure reclamation and other performance commitments. The Partnership is not required to post collateral for these bonds.

The Partnership offers safe harbor 401(k) plans (the “Plans”) for all employees who are eligible to participate. Employees are immediately eligible to participate upon becoming a full-time employee with the Partnership and its subsidiaries and affiliates. The Plans allow for the deferral of all or part of a participant’s compensation, as defined by the Plans, up to the current limits provided by

the Internal Revenue Service. The safe harbor matching feature calls for the Partnership to contribute 100% of the first 3% of compensation a participant contributes, and 50% of the next 2% of compensation contributed by the participant. Partnership contributions under the Plans for the years ended December 31, 2014, 2013, and 2012 were $3.1 million, $2.5 million, and $2.4 million, respectively.

A summary of the unaudited quarterly results for the years ended December 31, 2014 and 2013 is presented below:

In the second quarter of 2014, we recorded an early extinguishment of debt loss of $5.0 million due to the early repayment of $210.0 million of principal under our Term Loan (see Note 9).

In the fourth quarter of 2014, we recorded a charge of $34.7 million to impair certain prepaid royalties with an affiliate (see Note 14).

In the third quarter of 2013, we recorded a loss of $77.8 million for the early extinguishment of debt which includes $72.1 million in tender costs and fees to redeem the 2017 Senior Notes and the write-off of $5.7 million in unamortized deferred debt issuance costs and the net unamortized debt premium of the extinguished debt (see Note 9).

In the fourth quarter of 2013, we reversed $4.3 million in discretionary bonuses, which had been accrued ratably during the first three quarters of 2013.

Foresight Energy LP
Schedule II —Valuation and Qualifying Accounts


Description	Balance at Beginning of Period		Charged to Costs and Expenses		Charged to Other Accounts		Deductions		Other		Balance at End of Period
	(In Thousands)
2014
Reserves deducted from asset accounts:
Prepaid royalty recoupment reserve	$	—	$	34,700	$	—	$	—	$	—	$	34,700
Allowance for doubtful accounts		—		—		—		—		—		—
2013
Reserves deducted from asset accounts:
Prepaid royalty recoupment reserve	$	—	$	—	$	—	$	—	$	—	$	—
Allowance for doubtful accounts		—		—		—		—		—		—
2012
Reserves deducted from asset accounts:
Prepaid royalty recoupment reserve	$	—	$	—	$	—	$	—	$	—	$	—
Allowance for doubtful accounts		—		—		—		—		—		—

Item 9. Changes in and Disagreements With Accountant on Accounting and Financial Disclosure

We evaluated, under the supervision and with the participation of our management, including our chief executive officer and chief financial officer, the effectiveness of the design and operation of our disclosure controls and procedures as of December 31, 2014. Based on that evaluation, our management, including our chief executive officer and chief financial officer, concluded that the disclosure controls and procedures were effective in design and operation as of such date. There were no changes in our internal control over financial reporting during the fiscal quarter to which this report relates that have materially affected, or are reasonably likely to materially affect, our internal control over financial reporting.

There have been no changes in our internal control over financial reporting (as such term is defined in Rules 13a-15(f) and 15d-15(f) under the Exchange Act) during the quarter ended December 31, 2014 that have materially affected, or are reasonable likely to materially affect, our internal control over financial reporting.

This Annual Report on Form 10-K does not include an attestation report of the company’s registered public accounting firm due to a transition period established by rules of the Securities and Exchange Commission for newly public companies.

This Annual Report on Form 10-K does not include a report of management’s assessment regarding internal control over financial reporting due to a transition period established by rules of the Securities and Exchange Commission for newly public companies.

Item 10. Directors, Executive Officers and Corporate Governance of the Managing General Partner

We are managed and operated by the board of directors and executive officers of our general partner, Foresight Energy GP LLC, a subsidiary of Foresight Reserves. As a result of owning our general partner, Foresight Reserves has the right to appoint all members of the board of directors of our general partner, including those directors meeting the independence standards established by the NYSE. Our unitholders will not be entitled to elect our general partner or its directors or otherwise directly participate in our management or operations. Our general partner owes certain contractual duties to our unitholders as well as a fiduciary duty to its owners.

As of February 27, 2015, the board of directors of our general partner has five directors, two of whom are independent as defined under the standards established by the NYSE and the Exchange Act. The NYSE does not require a listed publicly traded limited partnership, like us, to have a majority of independent directors on the board of directors of our general partner or to establish a compensation committee or a nominating committee. However, our general partner is required to have an audit committee of at least three members, and all its members are required to meet the independence and experience standards established by the NYSE and the Exchange Act, subject to certain transitional relief during the one-year period following consummation of the Partnership’s IPO. We will add another independent director to the board of directors of our general partner and audit committee of our board of directors within one year from the listing of our common units on the NYSE such that there will be three independent directors on the board of directors and the audit committee of our board of directors will be wholly comprised of three independent members.

In evaluating an additional director, Foresight Reserves will assess whether a candidate possesses the integrity, judgment, knowledge, experience, skill and expertise that are likely to enhance the board’s ability to manage and direct our affairs and business, and to enhance the ability of committees of the board to fulfill their duties.

All of the executive officers of our general partner listed below will allocate their time between managing our business and affairs and the business and affairs of Foresight Reserves. The amount of time that our executive officers devote to our business and the business of Foresight Reserves varies in any given period based on a variety of factors. We expect that our executive officers will continue to devote as much time to the management of our business and affairs as is necessary for the proper conduct of our business and affairs. However, our executive officers’ fiduciary duties to Foresight Reserves and other obligations may prevent them from devoting sufficient time to our business and affairs.

Neither our general partner nor Foresight Reserves receives any management fee or other compensation in connection with our general partner’s management of our business, but we will reimburse our general partner for all expenses it incurs and payments it makes on our behalf. Our partnership agreement does not set a limit on the amount of expenses for which our general partner and its affiliates may be reimbursed. These expenses include salary, bonus, incentive compensation and other amounts paid to persons who perform services for us or on our behalf and expenses allocated to our general partner by its affiliates.

The following table shows information for the executive officers and directors of our general partner as of February 27, 2015. Directors hold office until their successors have been elected or qualified or until the earlier of their death, resignation, removal or disqualification. Executive officers serve at the discretion of the board of directors. There are no family relationships among any of our directors or executive officers. Some of our directors and some of our executive officers also serve as executive officers of Foresight Reserves.

Christopher Cline is the Chairman of our general partner’s board of directors and Principal Strategy Advisor. Mr. Cline has more than 30 years of experience in the coal industry. After attending Marshall University, he developed and operated over 25 coal mining, processing and transportation facilities in the Appalachian region and the Illinois Basin, including some of the most productive longwall mining operations in the country. During the past five years, Mr. Cline has focused his efforts primarily on developing Foresight. The experience and qualifications that led to the conclusion that Mr. Cline should serve as a Director include his formation and leadership of the Partnership since its inception, significant and broad experience in the coal industry, and his proven business acumen.

Michael J. Beyer is a member of the Board of Directors and President and Chief Executive Officer of our general partner. Mr. Beyer has more than 30 years of experience in management, operations, finance and acquisitions related to coal and other energy-related businesses. Before joining Foresight, Mr. Beyer served as President of AEP Coal, Inc. from 2002 to 2006, Vice President of Business Development at Enron Corp. from 1997 to 2002 and, prior thereto, Senior Vice President and Manager of the Natural Resource Department at PNC Bank. Mr. Beyer received his Masters in Business Administration from Duquesne University and his undergraduate degree in Mining Engineering from Pennsylvania State University. The experience and qualifications that led to the conclusion that Mr. Beyer should serve as a Director include his effective leadership of the Partnership’s operations, extensive experience in the energy and financial services industries and his strong operating and technical knowledge of all aspects of the Partnership’s business.

John F. Dickinson is a member of the Board of Directors of our general partner. Since 1995, Mr. Dickinson has been the President of The Cline Group, the coal exploration and development group founded by Christopher Cline. Since 2007, Mr. Dickinson has been a member of the Board of Managers of Foresight Reserves. Prior to joining The Cline Group in September 1995, Mr. Dickinson worked for U.S. Steel Mining Company Inc. from 1969 to 1995, serving as President from 1988 to 1995. Mr. Dickinson has more than 45 years of experience in the coal industry. Mr. Dickinson received his undergraduate degree in Mining Engineering from Virginia Polytechnic Institute. The experience and qualifications that led to the conclusion that Mr. Dickinson should serve as a Director include his involvement with the Partnership since its inception, extensive experience in the coal industry and his strong operating and technical knowledge of exploration and mining.

E. Hunter Harrison is an independent member of the Board of Directors of our general partner and the Audit Committee. Mr. Harrison has been the Chief Executive Officer of Canadian Pacific Railway Limited (NYSE: CP) since 2012. Previously, Mr. Harrison served as President and Chief Executive Officer of Canadian National from 2003 to 2009 and as the Executive Vice President and Chief Operating Officer from 1998-2002. He served on CN’s Board of Directors for 10 years. Mr. Harrison has almost 50 years of experience in the railroad industry. Mr. Harrison has served as a director on several railway companies and industry associations, including The Belt Railway of Chicago, Wabash National Corporation, The American Association of Railroads, Terminal Railway, TTX Company, CN, IC, and ICRR. The experience and qualifications that led to the conclusion that Mr. Harrison should serve as a Director include his deep and extensive experience in the railroad industry, his executive leadership of significant organizations and his management experience with public companies.

Daniel S. Hermann is an independent member of the Board of Directors of our general partner and also serves as Chairman of the Audit Committee. He was appointed to the Board of Directors in September 2014. Mr. Hermann is currently Chief Executive Officer of AmeriQual Group, LLC, a food packaging company and leading supplier of field rations to the United States Department of Defense. Prior to joining AmeriQual, he spent 23 years with Black Beauty Coal Company, where he held various titles, including President and Chief Executive Officer and Chief Financial Officer. During his tenure at Black Beauty, Mr. Hermann was part of a successful team that grew the company into the largest coal producer in the Illinois Basin. In 2003, Black Beauty was acquired by Peabody Energy and Mr. Hermann spent the next two years as Group Executive for Peabody’s Midwest Division. Mr. Hermann is currently on the Board of Directors of Deaconess Health Systems and serves as a member of the Audit and Compensation Committees. He also serves as a Director of Fifth Third Bank Southern Indiana. Mr. Hermann holds a Bachelor of Science degree from Indiana State University in Evansville and is a certified public accountant. The experience and qualifications that led to the conclusion that Mr. Hermann should serve as a member of the Board of Directors of our general partner and as Chairman of the Audit Committee include his extensive knowledge of the coal industry and his financial expertise.

Oscar A. Martinez is the Senior Vice President—Chief Financial Officer of our general partner. Before joining the Partnership in August 2011, Mr. Martinez served as Vice President and Treasurer at Cloud Peak Energy, Inc. from 2009 to July 2011. Prior to joining Cloud Peak Energy, Inc., Mr. Martinez worked for Qwest Communications International, Inc. from 2002 to 2009 where he served most recently as the Vice President and Assistant Treasurer. Mr. Martinez also held positions in Corporate Strategy and Capital Markets with Qwest Communications International. Prior to joining Qwest, Mr. Martinez worked as an investment banker with JP Morgan Chase. Mr. Martinez received his Masters in Business Administration from Harvard Business School and his undergraduate degree in Business Administration from Trinity University.

Christopher Moravec is the Executive Vice President—Chief Commercial Officer of our general partner. Before joining the Partnership in June 2012, Mr. Moravec was the Executive Vice President of Rhino Resource Partners LP from 2007 to 2012. During this period, Mr. Moravec also served on the board of directors for Rhino Eastern, a West Virginia-based metallurgical coal operation structured as a joint-venture with Patriot Coal Corporation. Prior to joining Rhino Resource Partners LP, Mr. Moravec worked for PNC Bank providing both direct and investment banking services exclusively to the coal industry. Mr. Moravec received his undergraduate degree in Mining Engineering from West Virginia University and a Masters in Business Administration from the University of Pittsburgh.

Rashda M. Buttar is the Senior Vice President—General Counsel & Corporate Secretary of our general partner. Before joining the Partnership in September 2011, Ms. Buttar served as Vice President, Associate General Counsel and Corporate Secretary of Patriot Coal Corporation from 2007 to August 2011. Prior to joining Patriot Coal Corporation, Ms. Buttar served as the Assistant General Counsel and Assistant Corporate Secretary of TALX Corporation from 2003 to 2007. Ms. Buttar received her Juris Doctor from Saint Louis University School of Law and her undergraduate degree in Russian and Eastern European Studies and Political Science from Saint Louis University.

Our board has determined that Mr. Harrison and Mr. Hermann are independent as defined by the rules of the NYSE and under Rule 10A-3 promulgated under the Exchange Act. In accordance with the rules of the NYSE, we must appoint one additional independent member within one year of the listing of our common units on the NYSE, or by June 17, 2015.

Interested parties may contact the chairpersons of any of our board committees, our board’s independent directors as a group or our full board in writing by mail to Foresight Energy LP, One Metropolitan Square, 211 North Broadway, Suite 2600, St. Louis, MO 63102, Attention: Corporate Secretary. All such communications will be delivered to the director or directors to whom they are addressed.

The board of directors of our general partner has an audit committee and a conflicts committee. We do not currently have a compensation committee, but rather the board of directors of our general partner approves equity grants to directors and employees.

We are required to have an audit committee of at least three members, and all its members are required to meet the independence and experience standards established by the NYSE and the Exchange Act, subject to certain transitional relief during the one-year period following consummation of our IPO. As of February 27, 2015, the audit committee includes two independent members; Messrs. Harrison and Hermann. The board of directors of our general partner has determined that Mr. Hermann qualifies as an “audit committee financial expert,” as such term is defined under SEC rules. A third independent member will be added to the audit committee within one year from the listing date of our common units on the NYSE.

The audit committee assists the board of directors in its oversight of the integrity of our financial statements and our compliance with legal and regulatory requirements and partnership policies and controls. The audit committee has the sole authority to (1) retain and terminate our independent registered public accounting firm, (2) approve all auditing services and related fees and the terms thereof performed by our independent registered public accounting firm, and (3) pre-approve any non-audit services and tax services to be rendered by our independent registered public accounting firm. The audit committee is also responsible for confirming the independence and objectivity of our independent registered public accounting firm. Our independent registered public accounting firm has been given unrestricted access to the audit committee and our management.

The members of the conflicts committee may not be officers or employees of our general partner or directors, officers or employees of its affiliates, including Foresight Reserves, and must meet the independence standards established by the NYSE and the Exchange Act to serve on an audit committee of a board of directors, along with other requirements in our partnership agreement. The independent members of the board of directors of our general partner serve on a conflicts committee to review specific matters that the board believes may involve conflicts of interest and determines to submit to the conflicts committee for review. The conflicts committee determines if the resolution of the conflict of interest is adverse to the interest of the partnership. Any matters approved by the conflicts committee are conclusively deemed to be approved by us and all of our partners and not a breach by our general partner of any duties it may owe us or our unitholders.

The board of directors of our general partner has adopted Corporate Governance Guidelines that outline important policies and practices regarding our governance. The board of directors of our general partner has also adopted a Code of Business Conduct and Ethics (the “Code”) that applies to all employees and officers of Foresight Energy LP and Foresight Energy GP, including its principal executive officer, principal financial and accounting officer, and members of the board.

We file annual, quarterly and current reports, and amendments to those reports, and other information with the Securities and Exchange Commission (“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, and Washington, D.C. 20549. Please call the SEC at 1-800- SEC-0330 for further information on the public reference room.

We also make the documents listed above, including our Corporate Governance Guidelines and Code , available without charge under the Investors Relations tab of website, www.foresight.com, Our annual, quarterly and current reports, and amendments to those reports, and other information filed with the SEC, are posted to the website as soon as practicable after we file or furnish them with the SEC. The information on our website is not part of this Annual Report on Form 10-K.

The board of directors of our general partner (the “Board”) is responsible for establishing and implementing our compensation programs. The Board seeks to ensure that the total compensation paid to our executive officers is fair, reasonable, and competitive. This compensation discussion and analysis (“CD&A”) provides information about our compensation objectives and policies for 2014 for our principal executive officer, our principal financial officer and our other most highly compensated executive officers and is intended to place in perspective the information contained in the executive compensation tables that follow this discussion. This CD&A provides a general description of our compensation programs and specific information about its various components.

Throughout this discussion, the following individuals are referred to collectively as the “Named Executive Officers” and are included in the Summary Compensation Table:

We believe our success depends on the continued contributions of our Named Executive Officers. While we do not maintain a formal compensation philosophy, our executive compensation programs are designed for the purpose of attracting, motivating and retaining experienced and qualified executive officers with compensation that recognizes individual merit and overall business results. Our compensation programs are also intended to support the attainment of our strategic objectives by tying the interests of our Named Executive Officers to those of our unitholders through operational and financial performance goals and equity based compensation.

The principal elements of our executive compensation programs are base salary, annual cash incentives, incentives in the form of phantom units and unit awards, and the employee benefit arrangements made available to our full-time employees generally. The employee benefit arrangements provided to our Named Executive Officers consist of life, disability and health insurance benefits, a qualified safe harbor 401(k) savings plan and paid vacation and holidays.

We did not have a compensation committee during 2014 and do not anticipate having a compensation committee in the immediate future. All compensation decisions with respect to our Named Executive Officers are made by the Board. In establishing and implementing our compensation programs, the responsibility of the Board included:

As a Director, our Principal Strategy Advisor and a substantial equity holder in the Partnership, Mr. Cline is closely involved in designing and monitoring our overall executive compensation programs. Mr. Cline’s specific role in determining compensation is to make recommendations to the other members of the Board on specific compensation decisions with respect to our President and Chief Executive Officer and general compensation design matters with respect to our other Named Executive Officers. In making such recommendations, Mr. Cline takes into account his general business knowledge and experience and his specific knowledge of the market in which we compete for talent.

Mr. Beyer’s role as our President and Chief Executive Officer in determining executive compensation is to make recommendations to the other members of the Board on compensation decisions for those other than himself based upon his assessment of the individual performance of each executive officer and our overall performance. In addition, in recommending specific levels or components of compensation, Mr. Beyer, like Mr. Cline, takes into account his general business knowledge and experience and his specific knowledge of the market in which we compete for talent.

During 2014, we did not retain the services of a compensation consultant or conduct benchmarking or specific market review of our compensation levels or practices. Instead, our compensation levels and practices are established by the Board based upon the recommendations of our Principal Strategy Advisor and our President and Chief Executive Officer.

For the year ended December 31, 2014, the principal components of compensation for the Named Executive Officers were base salary; annual cash incentives; equity-based awards and other compensation, including perquisites and retirement benefits.

We established the base salary for each Named Executive Officer based on consideration of many factors, including the individual’s performance and experience, the pay of others on the executive team and our Board’s assessment of the market in which we compete for talent. The base salary compensation is intended to provide security and a reliable, but not excessive, source of income to our Named Executive Officers.

Our Board periodically reviews the base salaries of our Named Executive Officers and has the discretion to make adjustments based upon any factor it deems relevant, including those described above. No Named Executive Officers received adjustments to their annual base salary during 2014.

We provide each of our Named Executive Officers with an opportunity to earn an annual cash incentive. Following the completion of each year, the Board determines the amount of each Named Executive Officer’s annual cash incentive for such year, if any, based upon their subjective determination of such individual’s respective individual contributions to the Partnership, to successful mining operations and to our overall performance during the year, in the area for which they are responsible. Such annual cash incentives to our Named Executive Officers are discretionary and therefore not based upon any pre-established performance metrics or targeted to any specific level of compensation.

For 2014, the Board determined the annual cash incentive for our Named Executive Officers to be as follows:

In connection with our initial public offering, we established a long-term incentive plan (the “LTIP”) which permits the Board to grant a variety of different types of equity compensation awards. For 2014, the equity compensation awards granted to certain Named Executive Officers were in the form of unit awards that vested immediately or phantom units, which will vest in full upon the completion of a fixed period of service following the date of grant. The number of units or phantom units awarded, and the vesting schedule for each was as follows:

Each phantom unit granted to our Named Executive Officers during 2014 will vest based upon continued service, and is not subject to any performance-based vesting criteria. In addition, each phantom unit award was granted with tandem distribution equivalent rights.

We believe that providing compensation in the form of unit awards or phantom units aligns our Named Executive Officer’s compensation with the interests of our unitholders by providing a direct link between the amount of compensation received and the price of our units. The amount of phantom units granted was determined by our Board, upon consultation with our Principal Strategy Advisor and our President and Chief Executive Officer, based upon their assessment of individual performance.

In each of December 2011, 2012 and 2013, we granted long-term incentive compensation awards (“LTIC Awards”) to certain of our Named Executive Officers, which vested or will vest pro rata over three years. Each installment of the LTIC Awards that vested prior to the completion of our initial public offering was paid in cash. From and after our initial public offering, the LTIC Awards that vested in 2014 was paid in the form of fully-vested common units issued pursuant to the LTIP with the remaining installments of the LTIC Awards being granted in the form of phantom units. During 2014, our Named Executive Officers received the number of fully-vested Unit Awards, representing the 2014 installment of the LTIC Awards, and phantom units, representing future installments of the LTIC Award, as follows:

Our Named Executive Officers are entitled to participate in group health, term life, and similar benefit plans available to all of our employees on the same terms as such employees. During 2014, Foresight Energy Services LLC maintained a plan intended to provide benefits under section 401(k) of the Code pursuant to which eligible employees are permitted to contribute portions of their compensation into a tax-qualified retirement account. For 2014, the plan provided safe harbor matching contributions equal to 100% of the first 3% of eligible compensation contributed by a participant to his or her account and 50% of the next 2% of eligible compensation contributed.

The Partnership provides a limited amount of perquisites and personal benefits to the Named Executive Officers.

We do not currently maintain any employment agreements or severance plans which cover our Named Executive Officers.

We are a limited partnership and not a corporation for U.S. federal income tax purposes. Therefore, we believe that the compensation paid to the named executive officers is not subject to the deduction limitations under Section 162(m) of the Internal Revenue Code and therefore is generally fully deductible for federal income tax purposes.

For our unit-based compensation arrangements, we record compensation expense over the vesting period of the awards, as discussed further in Item 8, “Financial Statements and Supplementary Data,” Note 18. Equity-Based Compensation” in this Annual Report on Form 10-K.

We believe our compensation programs for our Named Executive Officers, as well as our other employees, are appropriately structured and are not reasonably likely to result in material risk to us. We also believe our compensation programs are structured in a manner that does not promote excessive risk-taking that could harm our value or reward poor judgment. We believe we have allocated our compensation among base salary and short and long-term compensation programs in such a way as to not encourage excessive risk-taking. In particular, we generally do not adjust base annual salaries for the Named Executive Officers and other employees significantly from year to year, and therefore the annual base salary of our employees is not generally impacted by our overall financial performance or the financial performance of an operating segment. We use phantom units rather than unit options for equity awards because restricted units retain value even in a depressed market.

Our insider trading policy prohibits our directors and executive officers from engaging in any hedging or similar practices designed to offset a decrease in the price of our units.

We do not have a compensation committee. Our Board has reviewed and discussed the Compensation Discussion and Analysis with management and, based on such review and discussions approved the Compensation Discussion and Analysis included herein.

The following table summarizes the compensation we paid during the years ended December 31, 2014 and 2013 to our Named Executive Officers.

The following table sets forth, for each Named Executive Officer, information about grants of plan-based awards made during the year ended December 31, 2014. We did not grant any option or non-equity incentive plan compensation during 2014.

Our executive compensation policies and practices, pursuant to which the compensation set forth in the Summary Compensation Table and the Grants of Plan-Based Awards Table was paid or awarded, are described above in the section titled "Executive Compensation—Compensation Discussion and Analysis.”

The following table sets forth the percentage of each Named Executive Officer’s total compensation for the year ended December 31, 2014 that was paid in the form of base salary and bonus (including annual cash incentive awards and discretionary amounts, if any):

The following table reflects information regarding outstanding unit awards held by our Named Executive Officers as of December 31, 2014. None of our Named Executive Officers hold any option awards.

The following table reflects the lapse of restrictions, during the year ended December 31, 2014, on unit awards held by our Named Executive Officers. No Named Executive Officer held option awards during 2014 and 2013.

None of our Named Executive Officers participate in any defined benefit pension plans or nonqualified deferred compensation plans.

Generally, none of our Named Executive Officers are parties to any plans or agreements which provide for benefits in connection with termination of employment or upon a change of control. However, Rashda M. Buttar, our Senior Vice President —General Counsel & Corporate Secretary, is party to a letter agreement which provides that in the event her employment with our general partner is terminated by our general partner for any reason other than for “cause” (as defined in the letter agreement), Ms. Buttar would be entitled receive full vesting of any unvested portion of her phantom unit award granted on June 23, 2014. Assuming Ms. Buttar experienced a termination of employment without “cause” on December 31, 2014, she would have been able to receive accelerated vesting of phantom units worth $288,575, calculated based on the closing price of our common units on such date of $16.49.

The compensation of the directors of our general partner is set by the Board. Messrs. Cline, Beyer and Dickinson receive no director compensation.

(1) Amount represents the grant date fair value in accordance with FASB ASC 718, Stock Compensation.

Item 12. Security Ownership of Certain Beneficial Owners and Management and Related Unitholder Matters

The following table sets forth certain information as of February 27, 2015, regarding the beneficial ownership of common and subordinated units held by (a) each director of our managing general partner, (b) each executive officer of our managing general partner, (c) all such directors and executive officers as a group, and (d) each person known by our managing general partner to be the beneficial owner of 5% or more of our common units. Our managing general partner is owned by 99% by Foresight Reserves, which is reflected as a 5% common unitholder in the table below, and 1% by Michael J. Beyer, the Chief Executive Officer of our general partner. The address of each of Foresight Reserves, our general partner, and each of the directors and officers reflected in the table below is 3801 PGA Blvd., Suite 903, Palm Beach Gardens, Florida 33410. The percentage of units beneficially owned is based on 65,059,477 common units and 64,954,691 subordinated units outstanding.

Name of Beneficial Owner

Common Units Beneficially Owned

Percentage of Common Units Beneficially Owned

Subordinated Units Beneficially Owned

Percentage of Subordinated Units Beneficially Owned

Percentage of Common and Subordinated Units Beneficially Owned

5% Unitholders:

Foresight Reserves L.P. (a)

47,048,812

72.3

64,307,087

99.0

85.6

Executive Officers and Directors:

Christopher Cline

(b)

Michael J. Beyer

556,037

647,604

1.0

John F. Dickinson

—

E. Hunter Harrison

—

Daniel S. Hermann

10,000

—

Oscar A. Martinez

45,108

—

Rashda M. Buttar

20,113

—

Christopher Moravec

5,103

—

Aggregate - executive officers and directors

636,361

647,604

1.0

The following table sets forth information with respect to compensation plans under which our equity is authorized for issuance.

Item 13. Certain Relationships and Related-Party Transactions and Director Independence

As of February 27, 2015, Foresight Reserves, inclusive of common shares owned individually by Chris Cline, owned 47,048,812 common units and 64,307,087 subordinated units, representing an 85.6% limited partner interest in us. Foresight Reserves also owns 99.0% of our general partner, with the remainder being owned by a member of management.

The terms of the transactions and agreements disclosed in this section were determined by and among affiliated entities and, consequently, cannot be presumed to be the result of arm’s-length negotiations. These terms are not necessarily at least as favorable to the parties to these transactions and agreements as the terms that could have been obtained from unaffiliated third parties.

Affiliated entities principally include Foresight Reserves and its affiliates, the majority owner of us and our general partner, and NRP and its affiliates, for which Chris Cline owns a beneficial interest in the general partner and limited partner interests.

The following table summarizes the distributions and payments to be made by us to our general partner and its affiliates in connection with the formation, ongoing operation and any liquidation of Foresight Energy LP.

The net proceeds from the IPO were used to pay a $115.0 million special distribution to Foresight Reserves and a member of management and to repay $210.0 million of outstanding Term Loan principal.

Under our partnership agreement, we have agreed to register for resale under the Securities Act of 1933 and applicable state securities laws any common units, subordinated units or other limited partner interests proposed to be sold by our general partner or any of its affiliates or their assignees if an exemption from the registration requirements is not otherwise available. These registration rights continue for two years following any withdrawal or removal of our general partner. We are obligated to pay all expenses incidental to the registration, excluding underwriting discounts.

In August 2013, Foresight Energy LLC underwent a restructuring (the “2013 Reorganization”), pursuant to which:

In connection with the 2013 Reorganization, each of Williamson, Sugar Camp, Hillsboro and Macoupin entered into a transloading and storage agreement with Sitran. These agreements provide for the unloading of coal from railcars into stockpiles at Sitran and for the loading of coal from stockpiles into barges. Under these agreements each mine will pay Sitran a fee for each ton of coal offloaded, stored or transloaded at Sitran’s facility. Each agreement has an initial term of three years and will renew automatically for successive one-year periods unless terminated by either party. For the years ended December 31, 2014 and 2013, the mines paid $9.3 million and $3.1 million, respectively, in transloading fees with Sitran. As of December 31, 2014, we had $0.8 million and $0.6 million, respectively, in affiliate payable balances outstanding with Sitran. On February 25, 2015, Foresight Reserves and a member of management contributed Sitran to the Partnership (see “Contribution of Assets” below).

Concurrent with the 2013 Reorganization, a throughput agreement was entered into between Hillsboro and Hillsboro Transport for Hillsboro Transport to operate the Clean Coal Handling System for Hillsboro. The agreement, which has an initial term of ten years, grants Hillsboro Transport the right to be the exclusive provider of clean coal handling services for Hillsboro. After the initial ten-year term of the throughput agreement, the parties can agree to continue renewing the agreement in five-year increments (up to

16 times). At the expiration of each term, Hillsboro has an option to acquire the Clean Coal Handling System for its then fair value. As compensation for operating and maintaining the Clean Coal Handling System, Hillsboro Transport will receive $0.99 per ton for each ton of coal loaded through the Clean Coal Handling System, subject to a minimum quarterly payment of $1.25 million. Subsequent to the 2013 Reorganization date, Hillsboro Transport was determined to be a variable interest entity and Hillsboro consolidates Hillsboro Transport as the primary beneficiary. See our audited historical consolidated financial statements, and notes thereto, included elsewhere in this Annual Report on Form 10-K. For the years ended December 31, 2014 and 2013, Hillsboro Transport earned net income of $3.8 million and $2.0 million, respectively, under the throughput agreement, which is recorded as income attributable to noncontrolling interests in our consolidated statements of operations. On February 25, 2015, Foresight Reserves and a member of management contributed Hillsboro Transport to the Partnership (see “Contribution of Assets” below).

Adena Resources has various contractual water rights contracts with various state and local governments that are used to provide water to certain of our mines. Concurrent with the distribution of Adena Resources to Foresight Reserves, each of Williamson, Sugar Camp, Hillsboro and Macoupin entered into an agreement with Adena Resources providing for water resources to be available at each of the mines for use in mining operations. The agreements have an initial term of three years and automatically renew for successive periods of one year unless either party opts out of the agreement. Under the agreements, the mines pay Adena Resources the actual cost incurred by Adena Resources in furnishing water to the mine, including any capital expenditures necessary to fulfill its obligations under the agreements, plus an annual fee of $10,000. Subsequent to the 2013 Reorganization date, Adena Resources was determined to be a variable interest entity and we continue to consolidate Adena Resources as the primary beneficiary. See our audited historical consolidated financial statements included elsewhere in this Annual Report on Form 10-K. On February 25, 2015, Foresight Reserves and a member of management contributed Adena Resources to the Partnership (see “Contribution of Assets” below).

In connection with the 2013 Reorganization, Hillsboro entered into a development agreement with Colt (the “Hillsboro Development Agreement”). Pursuant to the Hillsboro Development Agreement, Hillsboro put in place the right to offer Colt the ability to develop one or two additional longwall coal mines, previously identified as the “Hillsboro 2” and “Hillsboro 3” longwall mines and associated transportation infrastructure in coal reserves leased by Colt to Hillsboro. If Colt accepts the offer to develop a mine and associated transportation related infrastructure, Hillsboro will automatically acquire the option to purchase the fully developed mines, but not the transportation assets, for fair market value. Hillsboro will have the right to exercise this fair market value purchase option during a twelve month period that begins when Colt has first sold 100,000 tons of clean coal produced by the longwall method from any new mine. Hillsboro will not have an option to purchase the fully developed transportation assets, but will pay a commercially reasonable fair market price for their use. In the event Colt develops a mine and Hillsboro elects not to exercise its option to purchase the mine, Hillsboro will surrender its rights to the coal associated with that mine under its lease with Colt.

In connection with the 2013 Reorganization, Macoupin entered into a development agreement with Colt (the “Macoupin Development Agreement”). Pursuant to the Macoupin Development Agreement, Macoupin put in place the right to offer Colt the ability to develop one longwall coal mine and associated transportation infrastructure in coal reserves previously identified by Macoupin for a low sulfur longwall mine. If Colt accepts the option to develop the mine and associated infrastructure, then Macoupin will automatically acquire the option to purchase the fully developed mine, but not the transportation assets, for fair market value. Macoupin will have the right to exercise this fair market value purchase option during a twelve month period that begins when Colt has first sold 100,000 tons of clean coal produced by the longwall method from the new mine. Macoupin will not have an option to purchase the fully developed transportation assets, but will pay a commercially reasonable fair market price for their use. In the event Colt develops a mine, and Macoupin elects not to purchase the mine, Macoupin will surrender its rights to the coal associated with that mine under its lease with Colt.

In connection with the 2013 Reorganization, Sugar Camp entered into a development agreement with Ruger (the “Sugar Camp Development Agreement”). Pursuant to the Sugar Camp Development Agreement, Sugar Camp put in place the right to offer Ruger the ability to develop one or two additional longwall coal mines and associated transportation infrastructure in coal reserves either leased by Ruger to Sugar Camp or reserves where Ruger has granted Sugar Camp the right to mine coal and pay a royalty to Ruger. These areas have been previously identified by Sugar Camp as the “Sugar Camp 3” and “Sugar Camp 4” longwall mines. If Ruger accepts the option to develop the mine and associated infrastructure, then Sugar Camp will automatically acquires the option to purchase the fully developed mine, but not the transportation assets, for fair market value. Sugar Camp will have the right to exercise this fair market value purchase option during a twelve month period that begins when Ruger has first sold 100,000 tons of clean coal

produced by the longwall method from any new mine. Sugar Camp will not have an option to purchase the fully developed transportation assets, but will pay a commercially reasonable fair market price for their use. In the event Ruger develops a mine and Sugar Camp elects not to purchase the mine, Sugar Camp will surrender its rights to the coal associated with that mine under its lease and overriding royalty agreement with Ruger.

On February 25, 2015, Foresight Reserves and a member of management contributed 100% of the equity of Sitran, Adena and Hillsboro Transport to the Partnership. The entities were contributed by Foresight Reserves and a member of management for no consideration. Sitran, Adena and Hillsboro Transport had an aggregate net book value of approximately $60 million at January 31, 2015.

We have engaged in a series of transactions with NRP and its affiliates, an entity in which Christopher Cline directly and indirectly beneficially owns 4% of the limited partnership interest and 31% of the limited partnership interests in NRP’s general partner. Foresight Reserves and its subsidiaries have sold to NRP or subsidiaries of NRP certain coal reserves and transportation assets in exchange for equity in NRP and its general partner as well as entering into a restricted business contribution agreement and leases under which we will make royalty payments and pay fees as we mine leased coal and use leased transportation facilities owned by NRP, all as more further described below. Subsidiaries of NRP for which we have transacted include HOD, WPP, Williamson Transport, LLC (“Williamson Transport”) and Independence Energy, LLC (“Independence”).

On January 4, 2007, Chris Cline, Foresight Reserves, Adena Minerals LLC and their respective affiliates (collectively, “Adena Entities”) and NRP executed a restricted business contribution agreement. The restricted business contribution agreement obligates the Adena Entities and their affiliates to offer NRP any business owned, operated or invested in by the Adena Entities, subject to certain exceptions, that either (a) owns, leases or invests in hard minerals or (b) owns, operates, leases or invests in identified transportation infrastructure relating to certain future mine developments by the Adena Entities in Illinois. NRP’s acquisition of certain coal reserves and infrastructure assets related to our Macoupin, Hillsboro and Sugar Camp mining complexes, discussed more fully below, were deals consummated under the restricted business contribution agreement with the Adena Entities. We are required to offer and could consummate additional deals under the Restricted Business Contribution Agreement in the future.

Williamson has a coal mining lease agreement with WPP with an initial term of 15 years and options for an additional five years or until all merchantable and mineable coal has been mined and removed. Williamson is required to pay the greater of 8.0% of the gross selling price or $2.50 per ton for the first eight million tons of clean coal mined from the leased premises in any calendar year. For all tonnage mined in excess of the eight million tons, the royalty is the greater of 5.0% of the gross selling price or $1.50 per ton of clean coal mined from the leased premises. In addition to the tonnage royalty, the quarterly minimum royalty is $2.0 million, payable on the 20th of January, April, July and October in each year this lease is in effect, for the prior quarter production. The minimum royalty is recoupable on future tons mined during the preceding nineteen quarters from the excess tonnage royalty on a first paid, first recouped basis. Furthermore, the lease provides for an overriding royalty of $0.10 per ton on the first 8.5 million tons mined from specific coal reserves outlined in the agreement. The lease also requires a wheelage payable at 0.5% of the gross selling price when foreign coal is transported over the premises. During the years ended December 31, 2014 , 2013 and 2012, Williamson paid $19.8 million, $21.9 million and $20.3 million, respectively, in royalties and other payments to WPP under this coal lease.

Williamson leases property from Williamson Transport under two surface leases with initial terms through October 15, 2031 and an option to extend the leases in five-year increments until all the coal leased from an NRP affiliate is mined on Williamson’s premises. Williamson Transport has the option to put the land to Williamson for its fair market value as determined by an independent appraiser at any time during the lease term. Additionally, under a separate lease with an initial term through March 12, 2018, Williamson pays $5,000 per year for use of the premises and a fee currently at $1.80 per ton for each ton of coal produced at Williamson that is loaded through the Williamson Loadout facility, which escalates approximately $0.02 per year throughout the term of the agreement. Williamson Transport may elect to renew or extend the sublease for successive five-year periods. If Williamson Transport elects not to renew the sublease, Williamson has the option to buy the Williamson Loadout facility for its fair market value as determined by an independent appraiser. Williamson receives a fee of $0.25 per ton from Williamson Transport for each ton of coal that is loaded through the Williamson Loadout facility in exchange for operating the load out. During the years ended December 31, 2014, 2013 and 2012, Williamson Transport was paid $9.7 million, $10.2 million and $11.7 million, respectively, under these leases (net of the operating fee paid to Mach Mining, LLC).

Another of the entities sold by the Adena Entities to NRP on January 4, 2007 was Independence, which had previously been owned by Foresight Reserves. We had previously entered into a coal mining lease with Independence to lease a certain tract of approximately 3,500 acres adjacent to the Williamson mining complex to perform certain mining activities on the tract. The term of

this agreement is 15 years and can be renewed for an additional five years or until all merchantable and mineable coal has been mined and removed.

Williamson is obligated to pay overriding royalties to WPP pursuant to a special warranty deed dated August 22, 1990 between its predecessors in interest, Coal Properties Corporation, Grantor and Fairview Land Company. Under this deed, WPP is owed an overriding royalty in the amount of $0.25 per ton for each ton of coal mined and sold by Williamson from the mineral reserves subject to the deed. During the years ended December 31, 2014, 2013 and 2012, Williamson paid $0.5 million, $0.5 million and $1.0 million, respectively, in overriding royalties to WPP under this agreement.

In January 2009, NRP acquired additional coal reserves and infrastructure assets related to Macoupin for $143.5 million. Simultaneous with the closing, Macoupin entered into a lease transaction with WPP and HOD for mining of the mineral reserves and for the rail facility, which we account for as a sale-leaseback financing arrangement. The mineral reserve mining lease is for a term of 20 years and can be extended for additional five-year terms limited to six such renewals. The lease requires a tonnage royalty equal to the greater of (i) 8% of the gross selling price of the coal plus $0.60 per ton or (ii) $5.40 per ton to be paid on the first 3.4 million tons of coal mined and sold in any given calendar year. Additionally, for the first 20-year term of the lease, Macoupin is required to pay a recoupable quarterly minimum deficiency payment equal to the difference between the tonnage royalty and $4.0 million. The lease also requires a wheelage fee of 0.5% of the gross selling price of any foreign coal transported across the property. During the years ended December 31, 2014, 2013 and 2012, Macoupin paid $16.2 million, $15.5 million and $14.9 million, respectively, in royalties and other payments to WPP under this mineral lease.

The Macoupin rail load-out facility and rail loop facility leases are for terms of 20 years with 16 renewals for five years each. For the first 30 years of the leases, each lease requires a payment of $1.50 per ton for every ton of coal loaded through the facility, up to 3.4 million tons per year. Annual rental payments of $10,000 per year are due after the expiration of the first 30 years. Macoupin is responsible for operations, repairs and maintenance and for keeping rail facilities in good working order. During the years ended December 31, 2014, 2013 and 2012, Macoupin paid $3.8 million, $3.0 million and $4.6 million, respectively, in payments to HOD under the rail facility leases.

Hillsboro entered into a coal mining lease agreement on September 10, 2009, with WPP. Under such agreement, Hillsboro leased certain mineral rights from WPP for a term of 20 years and can renew this lease for additional five-year terms, with a maximum of six terms or until all merchantable and mineable coal has been mined and removed. Hillsboro is required to pay WPP the greater of 8.0% of the gross selling price or $4.00 per ton and a fixed royalty in the amount set forth in the agreement for the coal mined from the leased premises. Hillsboro is subject to a minimum quarterly royalty under the agreement of $7.5 million until 2031, for the prior quarter’s production. Beginning with the quarterly minimum royalty due April 20, 2032, the quarterly minimum will be $125,000 for each quarter of 2032 and each subsequent quarter. The minimum royalty is recoupable on future tons mined. If during any quarter the tonnage royalty exceeds the applicable quarterly minimum royalty, Hillsboro may recoup any unrecouped quarterly deficiency payments made during the preceding twenty quarters from the excess tonnage royalty on a first paid, first recouped basis. We are a guarantor, on a declining basis, of the first $54.8 million of Hillsboro’s minimum quarterly payments to WPP. During the years ended December 31, 2014, 2013 and 2012, Hillsboro paid $28.6 million, $32.4 million and $32.2 million, respectively, to WPP under this lease. As of December 31, 2014, we paid WPP $44.5 million in advance minimum payments under this agreement that remain eligible for recoupment, of which $34.7 million has been reserved as we do not expect to recoup this balance based on the remaining recoupment period for certain minimum payments and our expected near-term Hillsboro sales given current coal market conditions.

Williamson has a coal mining lease agreement with Independence the term of which runs through March 13, 2021 and can be renewed for additional five-year periods or until all merchantable and mineable coal has been mined and removed. Williamson is required to pay Independence the greater of 9.0% of the gross selling price or $2.85 per ton for the coal mined from the leased premises. In addition to the tonnage royalty, Williamson is required to pay a quarterly minimum royalty of $416,750 in each year this lease is in effect, for the prior quarter production. The minimum royalty is recoupable on future tons mined. If during any quarter the tonnage royalty exceeds the $416,750 quarterly minimum royalty, Williamson may recoup any unrecouped quarterly deficiency payments made during the preceding nineteen quarters from the excess tonnage royalty on a first paid, first recouped basis. The lease also has a provision for a wheelage payable at 0.5% of the gross selling price when foreign coal is transported over the premises. Williamson has an overriding royalty agreement with Independence. As such, Independence will receive an overriding royalty interest in the amount of $0.30 per ton for each ton of clean coal mined from certain mineral reserves identified in the agreement that Williamson controls or in the future will control that are sold to any third party for the life of the Williamson mining operations on the identified mineral reserves. During the years ended December 31, 2014, 2013 and 2012, Williamson paid $3.8 million, $6.0 million, and $9.5 million respectively, in royalties and other payments to Independence. As of December 31, 2014, we paid Independence $1.3 million in advance minimum payments that remain eligible for recoupment.

In March 2012, HOD acquired a rail load-out facility at Sugar Camp for $50.0 million The transaction includes a lease of the rail load-out to Sugar Camp for which Sugar Camp is required to pay to HOD a $1.50 per ton tonnage fee, subject to adjustment, on certain tonnages of coal loaded through the load-out during the first 20 years of the lease, subject to a minimum recoupable quarterly

deficiency payment of $1.3 million. After the first 20 years, Sugar Camp may elect to extend the lease for additional 5-year terms up to a maximum of 16 times. Sugar Camp has the option to purchase the rail load-out for fair market value at any time after the expiration of the first 20 years and for the remainder of the lease. The lease also requires Sugar Camp to maintain and operate the load-out. We are a guarantor, on a declining basis, of the first $15 million of Sugar Camp’s minimum quarterly payments to HOD. During the years ended December 31, 2014, 2013 and 2012, Sugar Camp made $6.2 million, $6.2 million and $4.1 million, respectively, in payments to HOD under the load out lease.

In addition, we have entered into various ancillary agreements with NRP and its subsidiaries providing for acquisition of additional mineral rights within the assigned reserves of Williamson and Macoupin, all in support of our mining transactions with NRP for leased reserves.

As a result of these transactions and contracts, as of December 31, 2014, we had $7.0 million of net outstanding payable to NRP and its affiliates, $5.6 million in accrued interest and $193.4 million in sales-leaseback obligations recorded to consolidated balance sheet. As of December 31, 2013, we had $4.9 million of net outstanding payables to NRP and its affiliates, $9.1 million in accrued interest and $193.4 million in sales-leaseback obligations recorded to our consolidated balance sheet. During the years ended December 31, 2014, 2013 and 2012, we paid NRP and its affiliates $88.7 million, $95.6 million and $98.3 million, respectively, in aggregate payments under the agreements described herein (inclusive of the sale-leaseback arrangements).

The following presents future minimum royalties, by year, required under noncancelable royalty agreements (inclusive of our sale-leaseback obligations) with NRP and its affiliates as of December 31, 2014 (in millions):

As part a reorganization in 2010, we entered into a series of mineral leases requiring minimum royalty payments and production royalty payments with Colt LLC (“Colt”) and Ruger Coal Company, LLC (“Ruger”), affiliates both owned by Foresight Reserves.

Williamson leases coal reserves from Colt. The term of this lease is for ten years with six renewal periods of five years each. Williamson is required to pay the greater of $3.40 per ton or 8.5% of the gross sales price of such coal. The minimum royalty for this lease, which is recoupable only against actual production royalty from future tons mined during the period of 10 years following the date on which any such minimum royalty is paid, is $2.0 million per year. During the years ended December 31, 2014, 2013 and 2012, Williamson paid $2.0 million, $2.1 million, and $3.0 million, respectively, in royalties to Colt under this coal lease. As of December 31, 2014, we paid Colt $5.1 million in advanced minimum royalty payments that remain eligible for recoupment.

Hillsboro leases coal reserves from Colt, the terms of which are identical but that each covers different reserves. The term of each of these leases is for five years with seven renewal periods of five years each. Hillsboro is required to pay the greater of $3.40 per ton or 8.5% of the gross sales price of such coal. The minimum royalty for each of these leases, which is recoupable only against actual production royalty from future tons during the period of 10 years following the date on which any such minimum royalty, is $4.0 million. Hillsboro paid $8.0 million in each of the years ended December 31, 2014, 2013 and 2012 in royalties to Colt under this coal lease. As of December 31, 2014, Hillsboro paid Colt $27.6 million in advanced minimum royalty payments that remain eligible for recoupment.

Sugar Camp leases coal reserves from Ruger. The term of this lease is for ten years with six renewal periods of five years each. Sugar Camp is required to pay the greater of $3.40 per ton or 8.5% of the gross sales price of such coal. There is no minimum royalty associated with this lease. Sugar Camp has two overriding royalty agreements with Ruger pursuant to which Sugar Camp is given the right to mine certain reserves controlled by Ruger as lessee. Pursuant to these overriding royalty agreements, the total royalty that Sugar Camp will be required to pay for each ton of coal mined is equal to the difference between (i) the actual production royalty paid by Sugar Camp to the lessor of the reserves under the leases assumed by Sugar Camp from Ruger and (ii) the amount which is equal to 8% of the gross selling price of the coal mined under the leases. In addition to the overriding royalty, the remaining future minimum royalty for each of these agreements, which is recoupable only against actual overriding royalty during the period of ten years following the date on which such overriding royalty was paid, is $1.0 million. During the years ended December 31, 2014, 2013 and

2012, Sugar Camp paid $11.5 million, $7.4 million and $8.2 million, respectively, in royalties to Ruger under these coal lease and overriding royalty agreements described above. As of December 31, 2014, Sugar Camp paid Ruger $2.0 million in advanced minimum royalty payments under the overriding royalty agreements that remain eligible for recoupment.

Macoupin leases coal reserves from Colt under two leases, the terms of which are identical but that cover different reserves. The term of these leases is for ten years with six renewal periods of five years each. Macoupin is required to pay the greater of $3.40 per ton or 8.5% of the gross sales price of such coal. The remaining future minimum royalties for each of these leases, which is recoupable only against actual production royalty from future tons mined during the period of 10 years following the date on which any such minimum royalty is paid, is $2.0 million.

Effective June 1, 2012 Macoupin leased additional coal reserves from Colt under another lease. The term of this lease is ten years with six renewal periods of five years each. Macoupin is required to pay the greater of $3.40 per ton or 8.5% of the gross sales price of such coal, subject to minimum annual payments of $0.5 million in 2013 and $2.0 million per year thereafter. Minimum annual payments are recoupable only against actual production royalty from future tons mined during the period of 10 years following the date on which any such minimum royalty is paid.

During the years ended December 31, 2014, 2013 and 2012, Macoupin paid $6.0 million, $6.0 million and $4.7 million, respectively, in royalties to Colt under these coal leases. As of December 31, 2014, Macoupin paid Colt $19.0 million under these leases in advanced minimum payments that remain eligible for recoupment.

As of December 31, 2014 and 2013, the mines had $0 and $0.2 million, respectively, in aggregate outstanding payables to Colt and Ruger under all of the leases above. During the years ended December 31, 2014, 2013 and 2012, we paid Colt and Ruger $25.5 million, $23.5 million and $23.9 million, respectively, in aggregate royalty payments under the agreements described herein.

The following presents future minimum royalties, by year, required under noncancelable royalty agreements with Foresight Reserves and its affiliates as of December 31, 2014 (in millions):

New River Royalty, LLC (“New River Royalty”) (formerly Williamson Development Company LLC), an affiliate owned by Foresight Reserves, entered into mitigation agreements with each of Hillsboro, Macoupin, Sugar Camp and Williamson on August 12, 2010 (“Mitigation Agreements”). The Mitigation Agreements are contracts providing for the mitigation by each of the coal mining companies of subsidence damage to any structures located on certain surface lands owned by New River Royalty. Under these agreements, the mining companies are obligated to either repair any significant damage to structures on New River Royalty’s surface lands caused by mine subsidence or compensate New River Royalty for the diminution in value of the structure caused by the subsidence damage, in satisfaction of their obligation under the Illinois Surface Coal Mining and Conservation and Reclamation Act, 225 ILCS 720/1.01 et. seq. As an alternative, under the Mitigation Agreements, the mining companies can elect to pay New River Royalty the appraised value of any structures expected to be impacted by subsidence activities prior to mining in exchange for a waiver of liability for any obligation to repair or compensate New River Royalty for any damage after subsidence occurs. Appraised values and diminution in value are determined by licensed appraisers.

In August 2011, an affiliated company owned by Foresight Reserves acquired the IC RailMarine Terminal in Convent, Louisiana. This terminal, commonly referred to as the Convent Marine Terminal (“CMT”), is owned by Raven Energy LLC (“Raven”), an entity controlled by Christopher Cline and beneficially owned by Christopher Cline, trusts for his children and entities beneficially owned by his management team. The terminal is designed to ship and receive commodities via rail, river barge and ocean vessel. We have a contract for throughput at the terminal that continues through December 31, 2021. We pay fees under the contract based on the tonnages of coal we move through the terminal, subject to minimum annual take-or-pay volume commitments throughout the duration of the contract. The minimum annual commitment amount under the rail transportation agreement is $42.3 million for

2015 and thereafter increases on average by 4.4% per year. The aggregate remaining minimum contractual payments remaining under this agreement is $338.5 million as of December 31, 2014. For the years ended December 31, 2014, 2013 and 2012, we paid $41.9 million, $26.1 million and $23.6 million, respectively, under this agreement. As of December 31, 2014 and 2013, we had an affiliate payable balance to Raven of $4.5 million and $3.2 million, respectively.

We operate each mine with a work force that is employed by a contractor that is not under common ownership by us, but is an “affiliate” of us due to our ability to exert control with respect to certain matters. We account for each of these operators as a variable interest entity. Due to the treatment of these contract operators as “variable interest entities,” their assets, liabilities and results of operations are reflected in our consolidated financial statements. For the years ended December 31, 2014 , 2013 and 2012, we paid $0.4 million and $0.3 million and $0.2 million, respectively, in the aggregate, plus reimbursement for actual costs incurred to these affiliated contract operators. See “Business—Employees and Labor Relations” for a detailed description of the agreements governing the relationship with these affiliated contract operators.

On August 1, 2013, Foresight Energy Services LLC entered into an equipment repair and rebuild agreement with Seneca Rebuild LLC (“Seneca Rebuild”), an affiliate owned by Chris Cline, to be the primary provider of repair and rebuild services for mining machinery and equipment for our mines. On April 1, 2014, we acquired Seneca Rebuild for $3.8 million (net of cash acquired).

On May 1, 2013, certain unaffiliated suppliers of mining products and Seneca Industries, Inc., one of our affiliates, formed a joint venture whose primary purpose is the manufacture and sale of certain mine supplies primarily for use by us in the conduct of our mining operations. In May 2013, we entered into an amendment to our existing supply agreement with the unaffiliated supplier parties that added the joint venture in which one of our affiliates owns 50% as a supplier party to the agreement, extended the term to April 2018 and updated the pricing provisions of the agreement. The agreement, as amended, obligates our mines to purchase at least 90% of their aggregate annual requirements for certain mine supplies from the supplier parties, subject to certain exceptions as set forth in the agreement. The mine supplies covered under this arrangement are sold pursuant to a price schedule incorporated into the agreement that is reviewed and, if necessary, adjusted every six months to result in an agreed-upon fixed profit percentage for the joint venture as set forth in the agreement. We and our affiliates purchased $18.1 million and $14.7 million in mining supplies from the joint venture during the years ended December 31, 2014 and 2013, respectively.

We are party to two surface leases in relation to the coal preparation plant and rail load out facility at Williamson with New River Royalty. The primary terms of the leases expire on October 15, 2021, but may be extended by Williamson for additional five-year terms under the same terms and conditions until all of the merchantable and mineable coal has been mined and removed from Williamson. Williamson is required to pay aggregate rent of $100,000 per year to New River Royalty under the leases. Additionally, New River Royalty may require Williamson to purchase any portion of either of the leased properties at any time while the leases are in effect for $3,000 an acre. Williamson Transport has the option to purchase any property optioned under the leases if Williamson does not perform its purchase obligation within fifteen days of receiving notice of its purchase obligation.

We may arrange air travel on an individual flight basis with affiliated entities controlled by The Cline Group. These expenses are incurred hourly (at estimated cost), by flight, and are initially paid by The Cline Group and then we reimburse The Cline Group. We also utilize other assets controlled by The Cline Group from time to time and reimburse The Cline Group on a time-incurred basis. For the years ended December 31, 2014 and 2013, we reimbursed entities controlled by The Cline Group $0 and $1.5 million, respectively, for usage of non-Foresight Energy LP assets.

Several affiliates by common ownership which own or lease property on which we conduct mining have obtained subsidence rights either from the surface owner or lessor. Normally, these rights permit us to subside the surface owner’s property in exchange for subsidence mitigation. The extent of the mitigation is normally determined at the time we undermine the surface and the cost is normally not material to our operations. Because those subsidence rights were previously held by affiliates by common ownership, we have entered into global assignments of such rights in exchange for our obligation to satisfy all subsidence mitigation.

Procedures for Review, Approval and Ratification of Transactions with Related Persons

If a conflict or potential conflict of interest arises between our general partner or its affiliates, on the one hand, and us or our unitholders, on the other hand, the resolution of any such conflict or potential conflict should be addressed by the conflicts committee. The members of the conflicts committee may not be officers or employees of our general partner or directors, officers or employees of its affiliates, including Foresight Reserves, and must meet the independence standards established by the NYSE and the Exchange Act to serve on an audit committee of a board of directors, along with other requirements in our partnership agreement. The independent members of the board of directors of our general partner serve on our conflicts committee to review specific matters that the board believes may involve conflicts of interest and determines to submit to the conflicts committee for review. The conflicts committee determines if the resolution of the conflict of interest is adverse to the interest of the partnership. Any matters approved by the conflicts committee are conclusively deemed to be approved by us and all of our partners and not a breach by our general partner of any duties it may owe us or our unitholders. The policy described above was adopted in connection with the IPO, and as a result the transactions executed prior to the IPO were not reviewed under such policy.

The information appearing under Item 10.“Directors, Executive Officers and Corporate Governance of the Managing Partner”—Director Independence” is incorporated herein by reference.

The following table presents fees for professional services rendered by our independent registered public accounting firm, Ernst and Young, LLP, during the years ended December 2014 and 2013:

The charter of the audit committee of the board of directors of our general partner provides that the audit committee is responsible for reviewing and approving, in advance, any audit and permissible non-audit engagement or relationship between us and our independent auditors, other than as provided under the de minimis exception rule.

Pursuant to the requirements 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 on March 10, 2015.

Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below by the following persons on behalf of the registrant and in the capacities and on the dates indicated.

Delaware		80-0778894
(State or other jurisdiction of incorporation or organization)		(I.R.S. Employer Identification No.)

211 North Broadway, Suite 2600, Saint Louis, MO		63102
(Address of principal executive offices)		(Zip code)


Title of Each Class		Name of Each Exchange On Which Registered
Common Units representing limited partner interests		New York Stock Exchange

Large accelerated filer	¨	Accelerated filer	¨

Non-accelerated filer	x (do not check if a smaller reporting company)	Smaller reporting company	¨


- Williamson Energy LLC	- Foresight Coal Sales LLC	- Foresight Receivable LLC
- Hillsboro Energy LLC	- Oeneus LLC d/b/a Savatran LLC	- Sitran LLC (effective 2/25/2015)
- Macoupin Energy LLC	- Foresight Energy Services LLC	- Hillsboro Transport LLC (effective 2/25/2015)
- Sugar Camp Energy LLC	- Foresight Energy Employee Services Corporation	- Adena Resources LLC (effective 2/25/2015)
- Tanner Energy LLC	- Seneca Rebuild LLC

Period	High		Low		Distribution per Limited Partner Unit
2nd Quarter 2014	$	20.78	$	18.50	$0.03 (declared August 5, 2014, paid August 29, 2014)
3rd Quarter 2014	$	20.75	$	16.67	$0.35 (declared November 6, 2014, paid November 25, 2014)
4th Quarter 2014	$	19.30	$	14.55	$0.36 (declared February 6, 2015, paid February 27, 2015)

PART I

Item 1. Business	2

Item 1A. Risk Factors	17

Item 1B. Unresolved Staff Comments	41

Item 2. Properties	42

Item 3. Legal Proceedings	43

Item 4. Mine Safety Disclosures	43

PART II

Item 5. Market for Registrant’s Common Equity, Related Unitholder Matters and Issuer Purchases of Equity Securities	44

Item 6. Selected Financial Data	46

Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations	48

Item 7A. Quantitative and Qualitative Disclosures About Market Risk	60

Item 8. Financial Statements and Supplementary Data	62

Item 9. Changes in and Disagreements With Accountant on Accounting and Financial Disclosure	92

Item 9A. Controls and Procedures	92

Item 9B. Other Information	93

PART III

Item 10. Directors, Executive Officers and Corporate Governance of the Managing General Partner	93

Item 11. Executive Compensation	97

Item 12. Security Ownership of Certain Beneficial Owners and Management and Related Unitholder Matters	105

Item 13. Certain Relationships and Related-Party Transactions and Director Independence	106

Item 14. Principal Accountant Fees and Services	114

PART IV
Item 15. Exhibits and Financial Schedules	115

			Proven and		Production (4)
	Available Mining	Transportation	Probable		Year Ended December 31,
Complex	Methods (1)	Access (2)	Reserves (3)		2014		2013		2012
			(In Millions of Tons)
Williamson	LW, CM	Rail (CN), Barge (OHR, MSR), Truck		383.8		6.5		6.7		7.5
Sugar Camp	LW, CM	Rail (CN, NS, CSX, BNSF), Barge (OHR, MSR), Truck		1,359.7		9.1		6.5		4.7
Hillsboro	LW, CM	Rail (UP, NS, CN), Barge (OHR, MSR), Truck		870.6		5.6		4.8		2.4
Macoupin	CM, LW	Rail (UP, NS, CN), Barge (OHR, MSR), Truck		457.1		1.6		0.7		1.7
				3,071.2		22.8		18.7		16.3


	Total Quarterly Distribution Per Common Unit	Marginal Percentage Interest in Distributions
		Unitholders			General Partner (IDRs)
Minimum quarterly distribution	$0.3375		100.0	%		—
First target distribution	Above $0.3375 up to $0.3881		100.0	%		—
Second target distribution	Above $0.3881 up to $0.4219		85.0	%		15.0	%
Third target distribution	Above $0.4219 up to $0.5063		75.0	%		25.0	%
Thereafter	Above $0.5063		50.0	%		50.0	%

	Priced		Unpriced (or Index Based)		Total
	(Tons, in Millions)
Year ending December 31, 2015		18.2		2.0		20.2
Year ending December 31, 2016		10.9		3.5		14.4


Machinery and equipment	3–20 years
Buildings and structures	3–40 years
Other	3–20 years

	December 31, 2014		December 31, 2013
	(In Thousands)
Trade accounts receivable	$	72,687	$	54,084
Other receivables		8,076		4,903
Total accounts receivable	$	80,763	$	58,987


Year		Percentage

2016		105.91%
2017		103.94%
2018		101.97%
2019 and thereafter		100.00%

	Long-Term Debt		Capital Lease Obligations
	(In Thousands)
2015	$	21,518	$	22,625
2016		21,518		21,936
2017		21,518		16,098
2018		341,018		11,267
2019		21,518		13,707
Thereafter		853,663		—
Total	$	1,280,753	$	85,633

In Thousands	2015			2016			2017			2018			2019
Minimum lease payments	$	21,000		$	21,000		$	21,000		$	21,000		$	21,000

	Royalties – Third Party		Royalties – Related Party		Transportation Minimums – Third Party		Transportation Minimums – Related Party
	(In Thousands)
2015	$	2,004	$	57,667	$	28,025	$	42,320
2016		2,004		57,667		28,025		44,160
2017		2,004		57,667		20,780		46,080
2018		2,004		57,667		20,780		48,160
2019		2,004		57,667		20,780		50,320
Thereafter		11,189		315,001		44,280		107,440
Total	$	21,209	$	603,336	$	162,670	$	338,480


	Operating Leases – Third Party		Operating Leases – Related Party
	(In Thousands)
2015	$	3,352	$	105
2016		2,227		105
2017		1,428		105
2018		680		105
2019		—		100
Thereafter		—		200
Total	$	7,687	$	720

Affiliated Company	Balance Sheet Location	December 31, 2014		December 31, 2013
		(In Thousands)
Foresight Reserves and affiliated entities	Due from affiliates	$	387	$	368
NRP and affiliated entities	Due from affiliates		187		—
Total		$	574	$	368

Foresight Reserves and affiliated entities	Due to affiliates	$	8,730	$	4,521
NRP and affiliated entities	Due to affiliates		7,148		5,051
Total		$	15,878	$	9,572

Foresight Reserves and affiliated entities	Prepaid royalties	$	53,671	$	37,644
NRP and affiliated entities⁽¹⁾	Prepaid royalties		11,071		39,801
Total		$	64,742	$	77,445

	Fair Value at December 31, 2014
	Total		Level 1		Level 2		Level 3
	(In Thousands)
Coal derivative contracts	$	61,037	$	—	$	61,037	$	—
Total	$	61,037	$	—	$	61,037	$	—

	Fair Value at December 31, 2013
	Total			Level 1		Level 2		Level 3
	(In Thousands)
Coal derivative contracts	$	2,020		$	—	$	2,020	$	—
Liability Award		(11,700	)		—		—		(11,700	)
Total	$	(9,680	)	$	—	$	2,020	$	(11,700	)

	Fair Value at December 31, 2014
	Current – Coal Derivative Assets		Long-Term – Coal Derivative Assets		Accrued Expenses		Other Long-Term Liabilities
	(In Thousands)
Coal derivative contracts	$	36,080	$	24,957	$	—	$	—
Total	$	36,080	$	24,957	$	—	$	—

	Liability Award
	(In Thousands)
Balance at January 1, 2014	$	11,700
Recorded fair value losses (gains):
Included in earnings		690
Purchases, issuances and settlements		(12,390	)
Balance at December 31, 2014	$	—

Balance at January 1, 2013	$	—
Recorded fair value losses (gains):
Included in earnings		677
Capitalized into development costs		(217	)
Purchases, issuances and settlements		11,240
Balance at December 31, 2013	$	11,700

	Number of Units			Weighted Average Grant Date Fair Value per Unit

Non-vested grants at January 1, 2014		-		$	-
Granted		757,021		$	19.99
Vested		(146,162	)	$	20.00
Forfeited		(9,750	)	$	20.00
Non-vested grants at December 31, 2014		601,109		$	19.99

	For the Year Ended December 31, 2014
	1st Quarter		2nd Quarter			3rd Quarter		4th Quarter
	(In Thousands, Except per Unit Data)
Coal sales	$	242,723	$	266,677		$	299,964	$	300,040
Operating income	$	61,520	$	66,174		$	74,357	$	55,005
Net income	$	31,916	$	30,845		$	46,155	$	30,131
Net (loss) income attributable to limited partner units⁽¹⁾	N/A		$	(4,231	)	$	45,366	$	29,057
Basic and diluted (loss) income per limited partner unit⁽¹⁾	N/A		$	(0.03	)	$	0.35	$	0.22

	For the Year Ended December 31, 2013
	1st Quarter		2nd Quarter		3rd Quarter			4th Quarter
	(In Thousands, Except per Unit Data)
Coal sales	$	232,593	$	215,930	$	240,868		$	268,021
Operating income	$	57,420	$	41,927	$	49,488		$	55,352
Net income (loss)	$	29,220	$	14,167	$	(57,833	)	$	24,963
Net income attributable to limited partner units⁽¹⁾	N/A		N/A		N/A			N/A
Basic and diluted earnings per limited partner unit⁽¹⁾	N/A		N/A		N/A			N/A

Name	Age	Position
Christopher Cline	56	Chairman of the Board of Directors and Principal Strategy Advisor
Michael J. Beyer	56	Director and President & Chief Executive Officer
John F. Dickinson	65	Director
E. Hunter Harrison	70	Director
Daniel S. Hermann	57	Director
Oscar A. Martinez	45	Senior Vice President—Chief Financial Officer
Christopher N. Moravec	59	Executive Vice President—Chief Commercial Officer
Rashda M. Buttar	46	Senior Vice President—General Counsel & Corporate Secretary


Name	2014 Annual Cash Incentive
Michael J. Beyer	$2,450,000
Oscar A. Martinez	$250,000
Christopher N. Moravec	$300,000
Rashda M. Buttar	$175,000
H. Drexel Short	--


Name	Units Granted	Type of Award	Vesting Schedule

Michael J. Beyer	–	–	–
Oscar A. Martinez	55,000	Unit Award	--
Christopher N. Moravec	25,000	Phantom Unit	Cliff vests in 3 years
Rashda M. Buttar	17,500	Unit Award	--
	17,500	Phantom Unit	Cliff vests in 1 year
H. Drexel Short	–	–	–


Name	Number of Unit Awards	Number of Phantom Units	Vesting Date
Michael J. Beyer	–	–	–
Oscar A. Martinez	7,217	–	–
	–	5,833	December 20, 2015
	–	2,500	December 20, 2016
Christopher N. Moravec	6,250	--	–
	–	6,250	December 20, 2015
	–	4,167	December 20, 2016
Rashda M. Buttar	5,875	–	–
	–	4,875	December 20, 2015
	–	2,167	December 20, 2016
H. Drexel Short	–	–	–


Name and Principal Position	Year	Salary ($)	Bonus ($)	Unit Awards ($)(1)	Non-Equity Incentive Plan Compensation ($)	All Other Compensation ($)(2)	Total ($)
Michael J. Beyer President & Chief Executive Officer	2014	$618,000	$2,450,000	–	–	38,983	$3,106,953
Michael J. Beyer President & Chief Executive Officer	2013	$618,000	$700,000	–	–	$59,422	$1,377,422
Oscar A. Martinez Senior Vice President & Chief Financial Officer	2014	$400,000	$250,000	$1,411,000	–	$11,210	$2,072,210
Christopher N. Moravec Executive Vice President & Chief Commercial Officer	2014	$500,000	$300,000	$833,334	–	$90,821	$1,724,155
	2013	$500,000	$350,000	–	$41,667	$90,953	$982,620
Rashda M. Buttar Senior Vice President – General Counsel & Corporate Secretary	2014	$325,000	$175,000	$958,334	–	$11,210	$1,469,544
H. Drexel Short Former Senior Vice President (through March 31, 2014)	2014	$102,692	–	–	–	$2,797	$105,489
	2013	$750,000	$300,000	–	–	$13,033	$1,063,033


Name	Percentage of Total Compensation

Michael J. Beyer	99%
Oscar A. Martinez	31%
Christopher N. Moravec	46%
Rashda M. Buttar	34%
H. Drexel Short	97%


Name	Unit Awards
Name	Number of Units That Have Not Vested (#)(1)	Market Value of Units That Have Not Vested ($)(2)
Michael J. Beyer	–	–
Oscar A. Martinez	8,333	$140,578
Christopher N. Moravec	35,417	$597,485
Rashda M. Buttar	24,542	$430,894
H. Drexel Short	–	–

Plan Category	(a) Number of Units to Be Issued Upon Exercise of Outstanding Unit Options and Rights as of December 31, 2014		(b) Weighted Average Exercise Price of Outstanding Unit Options and Rights		(c) Number of Units Remaining Available for Future Issuance Under Equity Compensation Plans (Excluding Securities Reflected in Column (a)) as of December 31, 2014
Equity compensation plans approved by unitholders:
None		—		—		—

Equity compensation plans not approved by unitholders:
Long-term incentive plan (1)		601,110		—		6,853,838
Total for equity compensation plans		601,110		—		6,853,838

The consideration received by Foresight Reserves and a member of management for the contribution of their interests	•		Common and subordinated units of 47,238,895 and 64,738,895, respectively and
	•		the incentive distribution rights

2015	$	60.7
2016		60.6
2017		60.7
2018		60.6
2019		60.7
Thereafter		514.3
Total minimum lease payments	$	817.6

2015	$	18.0
2016		18.0
2017		18.0
2018		18.0
2019		18.0
Thereafter		6.0
Total minimum lease payments	$	96.0