Attached files

file filename
EX-32.1 - EX-32.1 - Foresight Energy LPfelp-ex321_201412319.htm
EX-32.2 - EX-32.2 - Foresight Energy LPfelp-ex322_201412316.htm
EX-31.1 - EX-31.1 - Foresight Energy LPfelp-ex311_201412318.htm
EX-95.1 - EX-95.1 - Foresight Energy LPfelp-ex951_201412317.htm
EX-31.2 - EX-31.2 - Foresight Energy LPfelp-ex312_2014123110.htm
EX-21.1 - EX-21.1 - Foresight Energy LPfelp-ex211_20141231655.htm
EX-23.1 - EX-23.1 - Foresight Energy LPfelp-ex231_201412311021.htm
EX-24.1 - EX-24.1 - Foresight Energy LPfelp-ex241_201412311591.htm
EX-10.81 - EX-10.81 - Foresight Energy LPfelp-ex1081_201412311767.htm
EX-10.78 - EX-10.78 - Foresight Energy LPfelp-ex1078_201412311764.htm
EX-10.79 - EX-10.79 - Foresight Energy LPfelp-ex1079_201412311765.htm
EX-10.80 - EX-10.80 - Foresight Energy LPfelp-ex1080_201412311766.htm
EXCEL - IDEA: XBRL DOCUMENT - Foresight Energy LPFinancial_Report.xls

 

 

 

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

WASHINGTON, DC 20549

 

FORM 10-K

 

(Mark One)

x

ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

For the fiscal year ended December 31, 2014

OR

¨

TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

For the transition period from          to          

Commission File Number: 001-36503

 

Foresight Energy LP

(Exact Name of Registrant as Specified in its Charter)

 

 

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)

Registrant’s telephone number, including area code: (314) 932-6160

 

Securities registered pursuant to Section 12(b) of the Act:

 

Title of Each Class

 

Name of Each Exchange On Which Registered

Common Units representing limited partner interests

 

New York Stock Exchange

Securities registered pursuant to Section 12(g) of the Act:  None

_______________

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.

 Large accelerated filer

 

¨

  

Accelerated filer

 

¨

 

 

 

 

Non-accelerated filer

 

x  (do not check if a smaller reporting company)

  

Smaller reporting company

 

¨

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.

 

 

 

 

 


 

 

TABLE OF CONTENTS

 

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

 

 

 

1

 

 


 

CAUTIONARY STATEMENT REGARDING FORWARD-LOOKING STATEMENTS

 

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.

 

REFERENCES WITHIN THIS ANNUAL REPORT

 

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.

 

 

PART I

Item 1. Business

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.  

2

 

 


 

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

(1)

The list below details the names of our operating subsidiaries. Certain of our non-corporate operating subsidiaries rely exclusively on affiliated contract mining companies for their operations, which are consolidated as variable interest entities.

- 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

 

(2)

The member of management refers to Michael J. Beyer, our general partner’s President and Chief Executive Officer.

(3)

Includes common units held by executive management and directors (other than Michael J. Beyer).  

(4)

Percentage ownership represents the aggregate limited partner units held by Foresight Reserves and Christopher Cline.


3

 

 


 

Mining Operations

 

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.

4

 

 


 

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

 

 

 

 

 

 

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

 

  

(1)

LW: Longwall; CM: Continuous miner. Williamson, Sugar Camp and Hillsboro use CM for development sections only. Macoupin does not currently mine with a longwall.

(2)

CN: Canadian National Railway Company; UP: Union Pacific Railroad Corporation; NS: Norfolk Southern Corporation; CSX: CSX Corporation; BNSF: BNSF Railway Company; OHR: Ohio River; MSR: Mississippi River.

(3)

As of December 31, 2014. With respect to Williamson, the reserves shown include approximately 10 million tons of reserves that are subject to partial ownership and lack of exclusive control.

(4)

As reported by MSHA, inclusive of tons produced for certain mines in development.

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.

Below is an illustrative diagram of the longwall mining process:

 

5

 

 


 

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.  

Williamson Mining Complex

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.

Sugar Camp Mining Complex

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

6

 

 


 

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.

Hillsboro Mining Complex

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.

Macoupin Mining Complex

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.

Transportation

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.  

7

 

 


 

Coal Marketing and Sales

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.

8

 

 


 

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.

Competition

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.

Employees and Labor Relations

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.

 

Mining Agreements

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,

9

 

 


 

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.

10

 

 


 

Environmental and Other Regulatory Matters

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.

Mine Safety and Health

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

11

 

 


 

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.

Black Lung

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.

U.S. Environmental Laws

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.

The Surface Mining Control and Reclamation Act (“SMCRA”)

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.

12

 

 


 

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.

Clean Air Act

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

13

 

 


 

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.

Resource Conservation and Recovery Act (“RCRA”)

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.

14

 

 


 

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.

Clean Water Act of 1972 (“CWA”)

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 Superfund Statutes

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.

Permits

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.

 

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 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 mine and reclamation plans by utilizing this geologic data and incorporating elements of the environmental data. The mine and reclamation plan incorporates the provisions of the SMCRA, the state programs and the complementary environmental programs that affect coal mining, including the CWA.

15

 

 


 

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.


16

 

 


 

Item1A. Risk Factors

 

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.

Risks Related to Our Business  

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:

The market price for coal;

The supply of, and demand for, domestic and foreign coal;

Competition from other coal suppliers;

The cost of using, and the availability of, other fuels, including the effects of technological developments;

Advances in power technologies;

The efficiency of our mines;

The amount of coal we are able to produce from our properties, which could be adversely affected by, among other things, operating difficulties and unfavorable geologic conditions;

The pricing terms contained in our long-term contracts;

Cancellation or renegotiation of contracts;

Legislative, regulatory and judicial developments, including those related to the release of GHGs;

The strength of the U.S. dollar;

 

Air emission, wastewater discharge and other environmental standards for coal-fired power plants or coal mines;

Delays in the receipt of, failure to receive, or revocation of necessary government permits;

Inclement or hazardous weather conditions and natural disasters;

Availability and cost or interruption of fuel, equipment and other supplies;

Transportation costs;

Availability of transportation infrastructure, including flooding and railroad derailments;

Cost and availability of our contract miners;

Availability of skilled employees; and

Work stoppages or other labor difficulties.

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

17

 

 


 

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:

Permits and other licensing requirements;

Surface subsidence from underground mining;

Contract miner health and safety;

Remediation of contaminated soil, surface water and groundwater;

Air emissions;

Water quality standards;

The discharge of materials into the environment, including wastewater;

Storage, treatment and disposal of petroleum products and substances which are regarded as hazardous under applicable laws or which, if spilled, could reach waterways or wetlands;

Storage and disposal of coal wastes including coal slurry under applicable laws;

Protection of human health, plant life and wildlife, including endangered and threatened species;

Reclamation and restoration of mining properties after mining is completed;

Wetlands protection;

Dam permitting; and

The effects, if any, that mining has on groundwater quality and availability.

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

18

 

 


 

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

19

 

 


 

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

20

 

 


 

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,

21

 

 


 

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.  

22

 

 


 

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

23

 

 


 

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

24

 

 


 

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:

Geologic and mining conditions, which may not be fully identified by available exploration data and may differ from our experience in areas we currently mine;

Future coal prices, operating costs and capital expenditures;

Excise taxes, royalties and development and reclamation costs;

Future mining technology improvements;

The effects of regulation by governmental agencies;

Ability to obtain, maintain and renew all required permits;

Employee health and safety needs; and

Historical production from the area compared with production from other producing areas.

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.

25

 

 


 

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

26

 

 


 

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 are dependent on our affiliated contract mining operators.

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

27

 

 


 

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:

Adverse geologic conditions including floor and roof conditions, variations in seam height, washouts and faults;

Fire or explosions from methane, coal or coal dust or explosive materials;

Industrial accidents;

Seismic activities, ground failures, rock bursts, or structural cave-ins or slides;

Delays in the receipt of, or failure to receive, or revocation of necessary government permits;

Changes in the manner of enforcement of existing laws and regulations;

Changes in laws or regulations, including permitting requirements and the imposition of additional regulations, taxes or fees;

Accidental or unexpected mine water inflows;

Delays in moving our longwall equipment;

28

 

 


 

Railroad derailments;

Inclement or hazardous weather conditions and natural disasters, such as heavy rain, high winds and flooding;

Environmental hazards;

Interruption or loss of power, fuel, or parts;

Increased or unexpected reclamation costs;

Equipment availability, replacement or repair costs; and

Mining and processing equipment failures and unexpected maintenance problems.

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

29

 

 


 

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

30

 

 


 

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.

Risks Inherent in an Investment in Us

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:

the amount of coal we are able to produce from our properties, which could be adversely affected by, among other things, operating difficulties and unfavorable geologic conditions;

the market price of coal;

the level of our operating costs, including reimbursement of expenses to our general partner;

the supply of and demand for domestic and foreign coal;

the timing of shipment of our contractual coal sales some of which are based on annual, not quarterly, minimum purchases;

the impact of delays in the receipt of, failure to maintain, or revocation of, necessary governmental permits;

the price and availability of other fuels;

the impact of existing and future environmental and climate change regulations, including those impacting coal-fired power plants;

the loss of, or significant reduction in, purchases by our largest customers;

the cost of compliance with new environmental laws;

the cost of power needed to run our mines;

 

worker stoppages or other labor difficulties;

cancellation or renegotiation of contracts;

prevailing economic and market conditions;

difficulties in collecting our receivables because of credit or financial problems of customers;

the effects of new or expanded health and safety regulations;

air emission, wastewater discharge and other environmental standards for coal-fired power plants or coal mines;

domestic and foreign governmental regulation, including changes in governmental regulation of the mining industry or the electric utility industry;

the proximity to and capacity of transportation facilities;

the availability of transportation infrastructure, including flooding and railroad derailments;

competition from other coal suppliers;

advances in power technologies;

the efficiency of our mines;

the pricing terms contained in our long-term contracts;

cancellation or renegotiation of contracts;

legislative, regulatory and judicial developments, including those related to the release of GHGs;

delays in the receipt of, failure to receive, or revocation of necessary government permits;

inclement or hazardous weather conditions and natural disasters, such as heavy rain, high winds and flooding;

31

 

 


 

transportation costs;

the cost and availability of our contract miners;

the availability of skilled employees;

changes in tax laws; and

force majeure events.

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

the level and timing of capital expenditures we make;

our debt service requirements and other liabilities;

fluctuations in our working capital needs;

our ability to borrow funds and access capital markets;

restrictions contained in debt agreements to which we are a party;

the amount of cash reserves established by our general partner; and

the cost of acquisitions.

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:

making it more difficult for us to satisfy our debt obligations;

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

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

 

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

increasing our vulnerability to adverse economic, industry or competitive developments.

32

 

 


 

 

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:

our general partner is allowed to take into account the interests of parties other than us, such as Foresight Reserves and a member of management, in exercising certain rights under our partnership agreement;

neither our partnership agreement nor any other agreement requires Foresight Reserves to pursue a business strategy that favors us;

our partnership agreement replaces the fiduciary duties that would otherwise be owed by our general partner with contractual standards governing its duties, limits our general partner’s liabilities and restricts the remedies available to unitholders for actions that, without such limitations, might constitute breaches of fiduciary duty;

Foresight Reserves and its affiliates are not limited in their ability to compete with us and may offer business opportunities or sell assets to third parties without first offering us the right to bid for them;

except in limited circumstances, our general partner has the power and authority to conduct our business without unitholder approval;

our general partner determines the amount and timing of asset purchases and sales, borrowings, issuances of additional partnership securities and the level of reserves, each of which can affect the amount of cash that is distributed to our unitholders;

 

our general partner determines the amount and timing of any cash expenditure and whether an expenditure is classified as a maintenance capital expenditure, which reduces operating surplus, or an expansion capital expenditure, which does not reduce operating surplus. This determination can affect the amount of cash from operating surplus that is distributed to our unitholders, which, in turn, may affect the ability of the subordinated units to convert.

our general partner may cause us to borrow funds in order to permit the payment of cash distributions, even if the purpose or effect of the borrowing is to make a distribution on the subordinated units, to make incentive distributions or to accelerate the expiration of the subordination period;

33

 

 


 

our partnership agreement permits us to distribute up to $125 million as operating surplus, even if it is generated from asset sales, non-working capital borrowings or other sources that would otherwise constitute capital surplus. This cash may be used to fund distributions on our subordination units or the incentive distribution rights;

our general partner determines which costs incurred by it and its affiliates are reimbursable by us;

our partnership agreement does not restrict our general partner from causing us to pay it or its affiliates for any services rendered to us or entering into additional contractual arrangements with its affiliates on our behalf;

our general partner intends to limit its liability regarding our contractual and other obligations;

our general partner may exercise its right to call and purchase common units if it and its affiliates own more than 80% of the common units;

our general partner controls the enforcement of obligations that it and its affiliates owe to us;

our general partner decides whether to retain separate counsel, accountants or others to perform services for us;

our general partner may transfer its incentive distribution rights without unitholder approval; and

our general partner may elect to cause us to issue common units to it in connection with a resetting of the target distribution levels related to our general partner’s incentive distribution rights without the approval of the conflicts committee of the board of directors of our general partner or the unitholders. This election may result in lower distributions to the common unitholders in certain situations.

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.

34

 

 


 

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:

our existing unitholders’ proportionate ownership interest in us would decrease;

the amount of cash available for distribution on each unit may decrease;

because a lower percentage of total outstanding units would be subordinated units, the risk that a shortfall in the payment of the minimum quarterly distribution would be borne by our common unitholders will increase;

 

the ratio of taxable income to distributions may increase;

the relative voting strength of each previously outstanding unit may be diminished; and

the market price of the common units may decline.

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:

how to allocate business opportunities among us and its affiliates;

35

 

 


 

whether to exercise its call right;

how to exercise its voting rights with respect to the units it owns;

whether to exercise its registration rights;

whether to elect to reset target distribution levels; and

whether or not to consent to any merger or consolidation of the partnership or amendment to the partnership agreement.

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:

whenever our general partner makes a determination or takes, or declines to take, any other action in its capacity as our general partner, our general partner is generally required to make such determination, or take or decline to take such other action, in good faith, and is not subject to any higher standard imposed by our partnership agreement, Delaware law, or any other law, rule or regulation, or at equity;

 

our general partner and its officers and directors are not liable for monetary damages or otherwise to us or our limited partners resulting from any act or omission unless there has been a final and non-appealable judgment entered by a court of competent jurisdiction determining that such losses or liabilities were the result of conduct in which our general partner or its officers or directors engaged in bad faith, meaning that they believed that the decision was adverse to the interest of the partnership or, with respect to any criminal conduct, with knowledge that such conduct was unlawful; and

our general partner will not be in breach of its obligations under the partnership agreement or its duties to us or our limited partners if a transaction with an affiliate or the resolution of a conflict of interest is:

(1)

approved by the conflicts committee of the board of directors of our general partner, although our general partner is not obligated to seek such approval; or

(2)

approved by the vote of a majority of the outstanding common units, excluding any common units owned by our general partner and its affiliates.

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

36

 

 


 

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.

37

 

 


 

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.

 

38

 

 


 

 

Tax Risks to Common Unitholders

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

39

 

 


 

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.

40

 

 


 

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.

 

 

Item 1B. Unresolved Staff Comments

 

None.


41

 

 


 

 

Item 2. Properties

Coal Reserves

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

 

 

 

 

 

 

 

 

 

 

(1)

In-Place Tons are on a dry basis.

(2)

Clean Recoverable Tons are based on mining recovery, average theoretical preparation plant yield, 94% preparation plant efficiency and product moisture.

(3)

With respect to Williamson, the total Clean Recoverable Tons shown include approximately 10 million tons of reserves that are subject to partial ownership and lack of exclusive control.

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

42

 

 


 

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.

 

Item 3. Legal Proceedings

 

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.

 

Item 4. Mine Safety Disclosures

 

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.

 

 

 


43

 

 


 

 

PART II.

 

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.

 

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)

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.

 

Incentive Distribution Rights

 

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.

 

Percentage Allocation of Available Cash from Operating Surplus

 

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.

44

 

 


 

 

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

 

 

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

%

 

Equity Compensation Plans

 

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.

 

Unregistered Sales of Equity Securities

 

None.

 

Use of Proceeds from Registered Securities

 

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.

 

Issuer Purchases of Equity Securities

 

None.

 

45

 

 


 

Item 6. Selected Financial Data

 

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

 

 

46

 

 


 

 

(1)

For the year ended December 31, 2012, $10.0 million was recognized as other operating income for a legal settlement with a customer on a coal sales contract.

(2)

Includes current portion of long-term debt and capital lease obligations. Total long-term debt and capital lease obligations does not include $143.5 million for the years ended December 31, 2011 and $193.4 million for the year ended December 31, 2014, 2013 and 2012 of certain sale-leaseback financing obligations that are characterized as financing arrangements due to the involvement of certain of our affiliates in mining the reserves and utilizing the equipment related to the leases.

(3)

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 disclosure of the differences between Adjusted EBITDA and U.S. GAAP results, including providing a reconciliation of Adjusted EBITDA to U.S. GAAP results, to enable users to perform their own analysis of our operating results.  Below is a reconciliation between net income from continuing operations attributable to controlling interests and Adjusted EBITDA for the years ended December 31, 2014, 2013, 2012, 2011 and 2010.

 

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