10-K 1 form10-k.htm

 

 

 

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

WASHINGTON, D.C. 20549

 

Form 10-K

 

[X] ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
   
  For the fiscal year ended December 31, 2016
   
  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: 001-34892

 

Rhino Resource Partners LP

(Exact name of registrant as specified in its charter)

 

Delaware

(State or other jurisdiction of

incorporation or organization)

 

27-2377517

(I.R.S. Employer

Identification No.)

     

424 Lewis Hargett Circle, Suite 250
Lexington, KY

(Address of principal executive offices)

 

40503

(Zip Code)

 

Registrant’s telephone number, including area code: (859) 389-6500

 

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

 

None

 

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

Common Units representing Limited Partner Interests

 

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 if disclosure of delinquent filers pursuant to Item 405 of Regulation S-K (§ 229.405 of this chapter) is not contained herein, and will not be contained, to the best of registrant’s knowledge, in definitive proxy or information statements incorporated by reference in Part III of this Form 10-K or any amendment to this Form 10-K. [  ]

 

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 [  ]

(Do not check if a
smaller reporting company)

Smaller reporting company [X]

 

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

 

As of June 30, 2016, the last business day of the registrant’s most recently completed second fiscal quarter, the aggregate market value of the registrant’s equity held by non-affiliates of the registrant was approximately $2.5 million based on the price at which the registrant’s common units were last sold on the OTCQB Marketplace on such date. As of March 17, 2017, the registrant had 12,905,799 common units, 1,235,534 subordinated units and 1,500,000 Series A preferred units outstanding.

 

DOCUMENTS INCORPORATED BY REFERENCE

 

Documents incorporated by reference in this report are listed in the Exhibit Index of this Form 10-K

 

 

 

   
 

 

TABLE OF CONTENTS

 

  PART I
Item 1. Business 1
Item 1A. Risk Factors 25
Item 1B. Unresolved Staff Comments 51
Item 2. Properties 51
Item 3. Legal Proceedings 54
Item 4. Mine Safety Disclosure 54
  PART II
Item 5. Market for Registrant’s Common Equity, Related Unitholder Matters and Issuer Purchases of Equity Securities 55
Item 6. Selected Financial Data 58
Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations 58
Item 7A. Quantitative and Qualitative Disclosures About Market Risk 88
Item 8. Financial Statements and Supplementary Data 88
Item 9. Changes in and Disagreements with Accountants on Accounting and Financial Disclosure 89
Item 9A. Controls and Procedures 89
Item 9B. Other Information 89
  PART III
Item 10. Directors, Executive Officers and Corporate Governance 89
Item 11. Executive Compensation 93
Item 12. Security Ownership of Certain Beneficial Owners and Management and Related Unitholder Matters 98
Item 13. Certain Relationships and Related Transactions, and Director Independence

99

Item 14. Principal Accounting Fees and Services 103
  PART IV
Item 15. Exhibits, Financial Statement Schedules 104
Item 16. Form 10K Summary 104
     
  FINANCIAL STATEMENTS  
  Index to Financial Statements F-1

 

 i 
 

 

GLOSSARY OF KEY TERMS

 

ash: Inorganic material consisting of iron, alumina, sodium and other incombustible matter that are contained in coal. The composition of the ash can affect the burning characteristics of coal.

 

assigned reserves: Proven and probable reserves that have the permits and infrastructure necessary for mining.

 

as received: Represents an analysis of a sample as received at a laboratory.

 

Btu: British thermal unit, or Btu, is the amount of heat required to raise the temperature of one pound of water one degree Fahrenheit.

 

Central Appalachia: Coal producing area in eastern Kentucky, western Virginia and southern West Virginia.

 

coal seam: Coal deposits occur in layers typically separated by layers of rock. Each layer is called a “seam.” A seam can vary in thickness from inches to a hundred feet or more.

 

coke: A hard, dry carbon substance produced by heating coal to a very high temperature in the absence of air. Coke is used in the manufacture of iron and steel.

 

fossil fuel: A hydrocarbon such as coal, petroleum or natural gas that may be used as a fuel.

 

GAAP: Generally accepted accounting principles in the United States.

 

high-vol metallurgical coal: Metallurgical coal that has a volatility content of 32% or greater of its total weight.

 

Illinois Basin: Coal producing area in Illinois, Indiana and western Kentucky.

 

limestone: A rock predominantly composed of the mineral calcite (calcium carbonate (CaCO3)).

 

lignite: The lowest rank of coal. It is brownish-black with high moisture content commonly above 35% by weight and heating value commonly less than 8,000 Btu.

 

low-vol metallurgical coal: Metallurgical coal that has a volatility content of 17% to 22% of its total weight.

 

mid-vol metallurgical coal: Metallurgical coal that has a volatility content of 23% to 31% of its total weight.

 

Metallurgical, or “met”, coal: The various grades of coal suitable for carbonization to make coke for steel manufacture. Its quality depends on four important criteria: volatility, which affects coke yield; the level of impurities including sulfur and ash, which affects coke quality; composition, which affects coke strength; and basic characteristics, which affect coke oven safety. Metallurgical coal typically has a particularly high Btu but low ash and sulfur content.

 

net mineral acre: The product of (i) the percentage of oil and natural gas mineral rights owned in a given tract of land and (ii) the total surface acreage of such tract.

 

non-reserve coal deposits: Non-reserve coal deposits are coal-bearing bodies that have been sufficiently sampled and analyzed in trenches, outcrops, drilling and underground workings to assume continuity between sample points, and therefore warrant further exploration stage work. However, this coal does not qualify as a commercially viable coal reserve as prescribed by standards of the SEC until a final comprehensive evaluation based on unit cost per ton, recoverability and other material factors concludes legal and economic feasibility. Non-reserve coal deposits may be classified as such by either limited property control or geologic limitations, or both.

 

Northern Appalachia: Coal producing area in Maryland, Ohio, Pennsylvania and northern West Virginia.

 

overburden: Layers of earth and rock covering a coal seam. In surface mining operations, overburden is removed prior to coal extraction.

 

 ii 
 

 

preparation plant: Usually located on a mine site, although one plant may serve several mines. A preparation plant is a facility for crushing, sizing and washing coal to prepare it for use by a particular customer. The washing process separates higher ash coal and may also remove some of the coal’s sulfur content.

 

probable (indicated) coal reserves: Coal reserves for which quantity and grade and/or quality are computed from information similar to that used for proven (measured) reserves, but the sites for inspection, sampling, and measurement are farther apart or are otherwise less adequately spaced. The degree of assurance, although lower than that for proven (measured) reserves, is high enough to assume continuity between points of observation.

 

proven (measured) coal reserves: Coal reserves for which (a) quantity is computed from dimensions revealed in outcrops, trenches, workings or drill holes; grade and/or quality are computed from the results of detailed sampling and (b) the sites for inspection, sampling and measurement are spaced so closely and the geologic character is so well defined that size, shape, depth and mineral content of reserves are well-established.

 

reclamation: The process of restoring land to its prior condition, productive use or other permitted condition following mining activities. The process commonly includes “re-contouring” or reshaping the land to its approximate original contour, restoring topsoil and planting native grass and shrubs. Reclamation operations are typically conducted concurrently with mining operations, but the majority of reclamation costs are incurred once mining operations cease. Reclamation is closely regulated by both state and federal laws.

 

recompletion: The process of re-entering an existing wellbore that is either producing or not producing and completing new oil and natural gas reservoirs in an attempt to establish or increase existing production.

 

reserve: That part of a mineral deposit which could be economically and legally extracted or produced at the time of the reserve determination.

 

steam coal: Coal used by power plants and industrial steam boilers to produce electricity, steam or both. It generally is lower in Btu heat content and higher in volatile matter than metallurgical coal.

 

sulfur: One of the elements present in varying quantities in coal that contributes to environmental degradation when coal is burned. Sulfur dioxide (SO2) is produced as a gaseous by-product of coal combustion.

 

surface mine: A mine in which the coal lies near the surface and can be extracted by removing the covering layer of soil overburden. Surface mines are also known as open-pit mines.

 

tons: A “short” or net ton is equal to 2,000 pounds. A “long” or British ton is 2,240 pounds. A “metric” tonne is approximately 2,205 pounds. The short ton is the unit of measure referred to in this report.

 

Western Bituminous region: Coal producing area located in western Colorado and eastern Utah.

 

 iii 
 

 

CAUTIONARY STATEMENT REGARDING FORWARD-LOOKING INFORMATION

 

This report contains “forward-looking statements.” Statements included in this report that are not historical facts, that address activities, events or developments that we expect or anticipate will or may occur in the future, including things such as statements regarding our future financial position, expectations with respect to our liquidity, capital resources and ability to continue as a going concern, plans for growth of the business, future capital expenditures, references to future goals or intentions or other such references are forward-looking statements. These statements can be identified by the use of forward-looking terminology, including “may,” “believe,” “expect,” “anticipate,” “estimate,” “continue,” or similar words. These statements are made by us based on our past experience and our perception of historical trends, current conditions and expected future developments as well as other considerations we believe are reasonable as and when made. Whether actual results and developments in the future will conform to our expectations is subject to numerous risks and uncertainties, many of which are beyond our control. Therefore, actual outcomes and results could materially differ from what is expressed, implied or forecast in these statements. Known material factors that could cause our actual results to differ from those in the forward-looking statements are those described in “Part 1, Item 1A. Risk Factors.” The following factors are among those that may cause actual results to differ materially from our forward-looking statements:

 

  our ability to maintain adequate cash flow and to obtain additional financing necessary to fund our capital expenditures, meet working capital needs and maintain and grow our operations or our ability to obtain alternative financing upon the expiration of our amended and restated senior secured credit facility and our related ability to continue as a going concern;
     
  our future levels of indebtedness and compliance with debt covenants;
     
  sustained depressed levels or further declines in coal prices, which depend upon several factors such as the supply of domestic and foreign coal, the demand for domestic and foreign coal, governmental regulations, price and availability of alternative fuels for electricity generation and prevailing economic conditions;
     
  our ability to comply with the qualifying income requirement necessary to maintain our status as a partnership for U.S. federal income tax purposes;
     
  declines in demand for electricity and coal;
     
  current and future environmental laws and regulations, which could materially increase operating costs or limit our ability to produce and sell coal;
     
  extensive government regulation of mine operations, especially with respect to mine safety and health, which imposes significant actual and potential costs;
     
  difficulties in obtaining and/or renewing permits necessary for operations;
     
  a variety of operating risks, such as unfavorable geologic conditions, adverse weather conditions and natural disasters, mining and processing equipment unavailability, failures and unexpected maintenance problems and accidents, including fire and explosions from methane;
     
  poor mining conditions resulting from the effects of prior mining; the availability and costs of key supplies and commodities such as steel, diesel fuel and explosives;
     
  fluctuations in transportation costs or disruptions in transportation services, which could increase competition or impair our ability to supply coal;
     
  a shortage of skilled labor, increased labor costs or work stoppages;
     
  our ability to secure or acquire new or replacement high-quality coal reserves that are economically recoverable;
     
  material inaccuracies in our estimates of coal reserves and non-reserve coal deposits;

 

 iv 
 

 

  existing and future laws and regulations regulating the emission of sulfur dioxide and other compounds, which could affect coal consumers and reduce demand for coal;
     
  federal and state laws restricting the emissions of greenhouse gases;
     
  our ability to acquire or failure to maintain, obtain or renew surety bonds used to secure obligations to reclaim mined property;
     
  our dependence on a few customers and our ability to find and retain customers under favorable supply contracts;
     
  changes in consumption patterns by utilities away from the use of coal, such as changes resulting from low natural gas prices;
     
  changes in governmental regulation of the electric utility industry;
     
  defects in title in properties that we own or losses of any of our leasehold interests;
     
  our ability to retain and attract senior management and other key personnel;
     
  material inaccuracy of assumptions underlying reclamation and mine closure obligations; and
     
  weakness in global economic conditions.

 

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

 

 v 
 

 

PART I

 

Unless the context clearly indicates otherwise, references in this report to “Rhino Predecessor,” “we,” “our,” “us” or similar terms when used for periods prior to the completion of the initial public offering of common units of Rhino Resource Partners LP on October 5, 2010 (the “IPO”) refer to Rhino Energy LLC and its subsidiaries. When used for periods subsequent to the completion of the IPO, “we,”“our,”“us,” or similar terms refer to Rhino Resource Partners LP and its subsidiaries. References to our “general partner” refer to Rhino GP LLC, the general partner of Rhino Resource Partners LP.

 

On April 18, 2016, we completed a 1-for-10 reverse split on our common units and subordinated units. Pursuant to the reverse split, common unitholders received one common unit for every 10 common units owned on April 18, 2016 and subordinated unitholders received one subordinated unit for every 10 subordinated units owned on April 18, 2016. All common and subordinated unit and distribution per unit references included herein have been adjusted as if the change took place before the date of the earliest transaction reported.

 

Item 1. Business.

 

We are a diversified energy limited partnership formed in Delaware that is focused on coal and energy related assets and activities, including energy infrastructure investments. We produce, process and sell high quality coal of various steam and metallurgical grades from multiple coal producing basins in the United States. We market our steam coal primarily to electric utility companies as fuel for their steam powered generators. Customers for our metallurgical coal are primarily steel and coke producers who use our coal to produce coke, which is used as a raw material in the steel manufacturing process. Our business includes investments in joint ventures to provide for the transportation of hydrocarbons and drilling support services in the Utica Shale region. We have also invested in joint ventures that provide sand for fracking operations to drillers in the Utica Shale region and other oil and natural gas basins in the United States.

 

We have a geographically diverse asset base with coal reserves located in Central Appalachia, Northern Appalachia, the Illinois Basin and the Western Bituminous region. As of December 31, 2016, we controlled an estimated 256.9 million tons of proven and probable coal reserves, consisting of an estimated 203.5 million tons of steam coal and an estimated 53.4 million tons of metallurgical coal. In addition, as of December 31, 2016, we controlled an estimated 196.5 million tons of non-reserve coal deposits. Both our estimated proven and probable coal reserves and non-reserve coal deposits as of December 31, 2016 decreased when compared to the estimated tons and deposits reported as of December 31, 2015 due to the sale of our Elk Horn coal leasing business in August 2016. As part of the recent audits of our coal reserves and deposits performed by Marshall Miller & Associates, Inc., this outside expert performed an independent pro forma economic analysis using industry-accepted guidelines and this was used, in part, to classify tonnage as either proven and probable coal reserves or non-reserve coal deposits, based on current market conditions.

 

We operate underground and surface mines located in Kentucky, Ohio, West Virginia and Utah. The number of mines that we operate will vary from time to time depending on a number of factors, including the existing demand for and price of coal, depletion of economically recoverable reserves and availability of experienced labor. In the third quarter of 2015, we temporarily idled a majority of our Central Appalachia operations due to ongoing weak coal market conditions for met and steam coal produced from this region. We resumed mining operations at all of our Central Appalachia operations in 2016 to fulfill customer contracts that we secured for 2016 and 2017.

 

For the year ended December 31, 2016, we produced and sold approximately 3.3 million tons of coal.

 

Our principal business strategy is to safely, efficiently and profitably produce and sell both steam and metallurgical coal from our diverse asset base in order to resume, and, over time, increase our quarterly cash distributions. In addition, we continue to seek opportunities to expand and diversify our operations through strategic acquisitions, including the acquisition of long-term, cash generating natural resource assets. We believe that such assets will allow us to grow our cash available for distribution and enhance stability of our cash flow.

 

1 
 

 

Current Liquidity and Outlook

 

As of December 31, 2016, our available liquidity was $13.0 million, including cash on hand of $0.1 million and $12.9 million available under our amended and restated credit agreement. On May 13, 2016, we entered into a fifth amendment (the “Fifth Amendment”) of our amended and restated agreement that initially extended the term of the senior secured credit facility to July 31, 2017. Per the Fifth Amendment, the term of the credit facility automatically extended to December 31, 2017 when the revolving credit commitments were reduced to $55 million or less as of December 31, 2016. The Fifth Amendment also immediately reduced the revolving credit commitments under the credit facility to a maximum of $75 million and maintains the amount available for letters of credit at $30 million. As of December 31, 2016, we met the requirements to extend the maturity date of the credit facility to December 31, 2017. In December 2016, we entered into a seventh amendment of our amended and restated credit agreement (the “Seventh Amendment”). The Seventh Amendment immediately reduces the revolving credit commitments by $11.0 million and provides for additional revolving credit commitment reductions of $2.0 million each on June 30, 2017 and September 30, 2017. The Seventh Amendment further reduces the revolving credit commitments over time on a dollar-for-dollar basis for the net cash proceeds received from any asset sales after the Seventh Amendment date once the aggregate net cash proceeds received exceeds $2.0 million. For more information about our amended and restated credit agreement, please read “Part 1, Item 1— Recent Developments-Amendments to Amended and Restated Credit Agreement.”

 

Since the current maturity date of our credit facility is December 31, 2017, we are unable to demonstrate that we have sufficient liquidity to operate our business over the next twelve months from the date of filing our Annual Report on Form 10-K and thus substantial doubt is raised about our ability to continue as a going concern. Accordingly, our independent registered public accounting firm has included an emphasis paragraph with respect to our ability to continue as a going concern in its report on our consolidated financial statements for the year ended December 31, 2016. The presence of the going concern emphasis paragraph in our auditors’ report may have an adverse impact on our relationship with third parties with whom we do business, including our customers, vendors, lenders and employees, making it difficult to raise additional debt or equity financing to the extent needed and conduct normal operations. As a result, our business, results of operations, financial condition and prospects could be materially adversely affected.

 

Since our credit facility has an expiration date of December 2017, we determined that our credit facility debt liability of $10.0 million at December 31, 2016 should be classified as a current liability on our consolidated statements of financial position. The classification of our credit facility balance as a current liability raises substantial doubt of our ability to continue as a going concern for the next twelve months. We are considering alternative financing options that could result in a new long-term credit facility. However, we may be unable to complete such a transaction on terms acceptable to us or at all. If we are unable to extend the expiration date of our credit facility, we will have to secure alternative financing to replace our credit facility by the expiration date of December 2017 in order to continue our business operations. If we are unable to extend the expiration date of our credit facility or secure a replacement facility, we will lose a primary source of liquidity, and we may not be able to generate adequate cash flow from operations to fund our business, including amounts that may become due under our credit facility. Furthermore, although met coal prices and demand have improved in recent months, if weak demand and low prices for steam coal persist and if met coal prices and demand weaken, we may not be able to continue to give the required representations or meet all of the covenants and restrictions included in our credit facility. If we violate any of the covenants or restrictions in our amended and restated credit agreement, including the maximum leverage ratio, some or all of our indebtedness may become immediately due and payable, and our lenders’ commitment to make further loans to us may terminate. If we are unable to give a required representation or we violate a covenant or restriction, then we will need a waiver from our lenders in order to continue to borrow under our amended and restated credit agreement. Although we believe our lenders loans are well secured under the terms of our amended and restated credit agreement, there is no assurance that the lenders would agree to any such waiver. Failure to obtain financing or to generate sufficient cash flow from operations could cause us to further curtail our operations and reduce our spending and to alter our business plan. We may also be required to consider other options, such as selling additional assets or merger opportunities, and depending on the urgency of our liquidity constraints, we may be required to pursue such an option at an inopportune time. If we are not able to fund our liquidity requirements for the next twelve months, we may not be able to continue as a going concern. For more information about our liquidity and our credit facility, please read “Part II, Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations —Liquidity and Capital Resources.”

 

We continue to take measures, including the suspension of cash distributions on our common and subordinated units and cost and productivity improvements, to enhance and preserve our liquidity so that we can fund our ongoing operations and necessary capital expenditures and meet our financial commitments and debt service obligations.

 

2 
 

 

Recent Developments

 

Sale of our General Partner by Wexford

 

On January 21, 2016 and March 17, 2016, Royal Energy Resources, Inc. (“Royal”) acquired from Wexford Capital LP (“Wexford Capital” and together with certain of its affiliates and principals, “Wexford”) all of the issued and outstanding membership interests of our general partner, 676,912 of our issued and outstanding common units and 945,525 issued and outstanding subordinated units. Royal is a publicly traded company listed on the OTC market (OTCQB: ROYE) and is focused on the acquisition of coal, natural gas and renewable energy assets that are profitable at current distressed prices. Immediately subsequent to the consummation of the transaction, the following members of the board of directors of our general partner tendered their resignations effective immediately: Mark Zand, Philip Braunstein, Ken Rubin, Arthur Amron, Douglas Lambert and Mark Plaumann. As the owner of our general partner, Royal has the right to appoint the members of the board of directors of our general partner and so appointed the following individuals as new directors to fill the vacancies resulting from the resignations: William Tuorto, Ronald Phillips, Michael Thompson, Ian Ganzer (who subsequently resigned in September 2016), Douglas Holsted, Brian Hughs and David Hanig.

 

On March 21, 2016, we and Royal entered into a securities purchase agreement (the “Securities Purchase Agreement”) pursuant to which we issued 6,000,000 of our common units to Royal in a private placement at $1.50 per common unit for an aggregate purchase price of $9.0 million. Royal paid us $2.0 million in cash and delivered a promissory note payable to us in the amount of $7.0 million (the “Rhino Promissory Note”). On May 13, 2016 and September 30, 2016, Royal paid us $3.0 million and $2.0 million, respectively, on the promissory note. The final installment on the promissory note of $2.0 million was due on or before December 31, 2016. However, on December 30, 2016, we modified the Securities Purchase Agreement with Royal to extend the due date of the final $2.0 million payment to December 31, 2018. Please read “—Letter Agreement Regarding Rhino Promissory Note and Weston Promissory Note.” In the event the disinterested members of the board of directors of our general partner determine that we do not need the capital that would be provided by the final installment, we have the option to rescind Royal’s purchase of 1,333,333 common units and the applicable installment will not be payable (each, a “Rescission Right”). If we fail to exercise a Rescission Right, we have the option to repurchase 1,333,333 of our common units at $3.00 per common unit from Royal (each, a “Repurchase Option”). The Repurchase Option terminates on December 31, 2017. Royal’s obligation to pay any installment of the promissory note is subject to certain conditions, including that we have entered into an agreement to extend the amended and restated credit agreement, as amended, to a date no sooner than December 31, 2017. In the event such conditions are not satisfied as of the installment due date, Royal has the right to cancel the remaining unpaid balance of the promissory note in exchange for the surrender of such number of common units equal to the principal balance of the promissory note divided by $1.50.

 

Pursuant to the Securities Purchase Agreement, on March 21, 2016, we and Royal entered into a registration rights agreement. The registration rights agreement grants Royal piggyback registration rights under certain circumstances with respect to the common units issued to Royal pursuant to the Securities Purchase Agreement.

 

Option Agreement

 

On December 30, 2016, we entered into an option agreement (the “Option Agreement”) with Royal, Rhino Resources Partners Holdings, LLC (“Rhino Holdings”), an entity wholly owned by certain investment partnerships managed by Yorktown Partners LLC (“Yorktown”), and our general partner. Upon execution of the Option Agreement, we received an option (the “Call Option”) from Rhino Holdings to acquire substantially all of the outstanding common stock of Armstrong Energy, Inc. (“Armstrong Energy”) that is owned by investment partnerships managed by Yorktown, representing approximately 97% of the outstanding common stock of Armstrong Energy. Armstrong Energy, Inc. is a coal producing company with approximately 554 million tons of proven and probable reserves and six mines located in the Illinois Basin in western Kentucky as of September 30, 2016. The Option Agreement stipulates that we can exercise the Call Option no earlier than January 1, 2018 and no later than December 31, 2019. In exchange for Rhino Holdings granting us the Call Option, we issued 5.0 million common units, representing limited partner interests in us (the “Call Option Premium Units”) to Rhino Holdings upon the execution of the Option Agreement. The Option Agreement stipulates we can exercise the Call Option and purchase the common stock of Armstrong Energy in exchange for a number of common units to be issued to Rhino Holdings, which when added with the Call Option Premium Units, will result in Rhino Holdings owning 51% of the fully diluted common units of us. The purchase of Armstrong Energy through the exercise of the Call Option would also require Royal to transfer a 51% ownership interest in our general partner to Rhino Holdings. Our ability to exercise the Call Option is conditioned upon (i) sixty (60) days having passed since the entry by Armstrong Energy into an agreement with its bondholders to restructure its bonds and (ii) the amendment of our revolving credit facility to permit the acquisition of Armstrong Energy.

 

The Option Agreement also contains an option (the “Put Option”) granted by us to Rhino Holdings whereby Rhino Holdings has the right, but not the obligation, to cause us to purchase substantially all of the outstanding common stock of Armstrong Energy from Rhino Holdings under the same terms and conditions discussed above for the Call Option. The exercise of the Put Option is dependent upon (i) the entry by Armstrong Energy into an agreement with its bondholders to restructure its bonds and (ii) the termination and repayment of any outstanding balance under our revolving credit facility.

 

3 
 

 

The Option Agreement contains customary covenants, representations and warranties and indemnification obligations for losses arising from the inaccuracy of representations or warranties or breaches of covenants contained in the Option Agreement, the Seventh Amendment (defined below) and the GP Amendment (defined below). Upon the request by Rhino Holdings, we will also enter into a registration rights agreement that provides Rhino Holdings with the right to demand two shelf registration statements and registration statements on Form S-1, as well as piggyback registration rights for as long as Rhino Holdings owns at least 10% of the outstanding common units.

 

Pursuant to the Option Agreement, the Second Amended and Restated Limited Liability Company Agreement of our general partner was amended (“GP Amendment”). Pursuant to the GP Amendment, Mr. Bryan H. Lawrence was appointed to the board of directors of our general partner as a designee of Rhino Holdings and Rhino Holdings has the right to appoint an additional independent director. Rhino Holdings has the right to appoint two members to the board of our general partner for as long as it continues to own 20% of the common units on an undiluted basis. The GP Amendment also provided Rhino Holdings with the authority to consent to any delegation of authority to any committee of the board of our general partner. Upon the exercise of the Call Option or the Put Option, the Second Amended and Restated Limited Liability Company Agreement of or general partner, as amended, will be further amended to provide that Royal and Rhino Holdings will each have the ability to appoint three directors and that the remaining director will be the chief executive officer of our general partner unless agreed otherwise.

 

The Option Agreement superseded and terminated the equity exchange agreement entered into on September 30, 2016 by and among Royal, Rhino Holdings, an entity wholly owned by certain investment partnerships managed by Yorktown, and our general partner.

 

Series A Preferred Unit Purchase Agreement

 

On December 30, 2016, we entered into a Series A Preferred Unit Purchase Agreement (the “Preferred Unit Agreement”) with Weston Energy LLC (“Weston”), an entity wholly owned by certain investment partnerships managed by Yorktown, and Royal. Under the Preferred Unit Agreement, Weston and Royal agreed to purchase 1,300,000 and 200,000, respectively, of Series A preferred units representing limited partner interests in us at a price of $10.00 per Series A preferred unit. The Series A preferred units have the preferences, rights and obligations set forth in our Fourth Amended and Restated Agreement of Limited Partnership, which is described below. In exchange for the Series A preferred units, Weston and Royal paid cash of $11.0 million and $2.0 million, respectively, to us and Weston assigned to us a $2.0 million note receivable from Royal originally dated September 30, 2016 (the “Weston Promissory Note”). Please read “—Letter Agreement Regarding Rhino Promissory Note and Weston Promissory Note.”

 

The Preferred Unit Agreement contains customary representations, warrants and covenants, which include among other things, that, for as long as the Series A preferred units are outstanding, we will cause CAM Mining, LLC, one of our subsidiaries, (“CAM Mining”) to conduct its business in the ordinary course consistent with past practice and use reasonable best efforts to maintain and preserve intact its current organization, business and franchise and to preserve the rights, franchises, goodwill and relationships of its employees, customers, lenders, suppliers, regulators and others having business relationships with CAM Mining.

 

The Preferred Unit Agreement stipulates that upon the request of the holder of the majority of our common units following their conversion from Series A preferred units, as outlined in our partnership agreement, we will enter into a registration rights agreement with such holder. Such majority holder has the right to demand two shelf registration statements and registration statements on Form S-1, as well as piggyback registration rights.

 

On January 27, 2017, Royal sold 100,000 of its Series A preferred units to Weston and its other 100,000 Series A preferred units to another third party.

 

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Letter Agreement Regarding Rhino Promissory Note and Weston Promissory Note

 

On December 30, 2016, we entered into a letter agreement with Royal whereby the maturity dates of the Weston Promissory Note and the final installment payment of the Rhino Promissory Note were extended to December 31, 2018. The letter agreement further provides that the aggregate $4.0 million balance of the Weston Promissory Note and Rhino Promissory Note may be converted at Royal’s option into a number of shares of Royal’s common stock equal to the outstanding balance multiplied by seventy-five percent (75%) of the volume-weighted average closing price of Royal’s common stock for the 90 days preceding the date of conversion (“Royal VWAP”), subject to a minimum Royal VWAP of $3.50 and a maximum Royal VWAP of $7.50.

 

Fourth Amended and Restated Partnership Agreement of Limited Partnership

 

On December 30, 2016, our general partner amended our partnership agreement to create, authorize and issue the Series A preferred units. The Series A preferred units are a new class of equity security that rank senior to all classes or series of our equity securities with respect to distribution rights and rights upon liquidation. The holders of the Series A preferred units shall be entitled to receive annual distributions equal to the greater of (i) 50% of the CAM Mining free cash flow (as defined below) and (ii) an amount equal to the number of outstanding Series A preferred units multiplied by $0.80. “CAM Mining free cash flow” is defined in our partnership agreement as (i) the total revenue of our Central Appalachia business segment, minus (ii) the cost of operations (exclusive of depreciation, depletion and amortization) for our Central Appalachia business segment, minus (iii) an amount equal to $6.50, multiplied by the aggregate number of met coal and steam coal tons sold by us from our Central Appalachia business segment. If we fail to pay any or all of the distributions in respect of the Series A preferred units, such deficiency will accrue until paid in full and we will not be permitted to pay any distributions on our partnership interests that rank junior to the Series A preferred units, including our common units. The Series A preferred units will be liquidated in accordance with their capital accounts and upon liquidation will be entitled to distributions of property and cash in accordance with the balances of their capital accounts prior to such distributions to equity securities that rank junior to the Series A preferred units.

 

The Series A preferred units will vote on an as-converted basis with the common units, and we will be restricted from taking certain actions without the consent of the holders of a majority of the Series A preferred units, including: (i) the issuance of additional Series A preferred units, or securities that rank senior or equal to the Series A preferred units; (ii) the sale or transfer of CAM Mining or a material portion of its assets; (iii) the repurchase of common units, or the issuance of rights or warrants to holders of common units entitling them to purchase common units at less than fair market value; (iv) consummation of a spin off; (v) the incurrence, assumption or guaranty indebtedness for borrowed money in excess of $50.0 million except indebtedness relating to entities or assets that are acquired by us or our affiliates that is in existence at the time of such acquisition or (vi) the modification of CAM Mining’s accounting principles or the financial or operational reporting principles of our Central Appalachia business segment, subject to certain exceptions.

 

Elk Horn Coal Leasing Disposition

 

In August 2016, we entered into an agreement to sell our Elk Horn coal leasing company to a third party for total cash consideration of $12.0 million. We received $10.5 million in cash consideration upon the closing of the Elk Horn transaction and the remaining $1.5 million of consideration will be paid in ten equal monthly installments of $150,000 on the 20th of each calendar month beginning on September 20, 2016. Elk Horn is a coal leasing company located in eastern Kentucky that provided us with coal royalty revenues from coal properties owned by Elk Horn and leased to third-party operators. As of December 31, 2015, Elk Horn controlled approximately 100 million tons of proven and probable steam coal reserves. During the second quarter of 2016, we evaluated the Elk Horn assets for potential impairment based upon the initial purchase price offered by the buyer and the continued deterioration of the Central Appalachia steam coal markets that had adversely affected Elk Horn’s financial results. Our impairment analysis determined that a potential impairment existed since the carrying amount of the Elk Horn long-lived asset group exceeded the cash flows that would be generated from the purchase price offered from the buyer. Based on a market approach used to estimate the fair value of the Elk Horn long-lived asset group, we recorded total asset impairment charges of approximately $118.7 million related to coal properties as of June 30, 2016. The disposal of the Elk Horn assets and liabilities in August 2016 resulted in an additional loss of $1.2 million. The total loss of $119.9 million from the Elk Horn disposal is recorded as discontinued operations along with the previous operating results of Elk Horn that have been reclassified for the years ended December 31, 2016 and 2015.

 

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Amended and Restated Credit Agreement Amendments

 

On March 17, 2016, our operating company, as borrower, and we and certain of our subsidiaries, as guarantors, entered into a fourth amendment (the “Fourth Amendment”) of our amended and restated credit agreement. The Fourth Amendment amended the definition of change of control in the amended and restated credit agreement to permit Royal to purchase the membership interests of our general partner.

 

On May 13, 2016, we entered into the Fifth Amendment of the amended and restated credit agreement , which extended the term to July 31, 2017.

 

In July 2016, we entered into a sixth amendment (the “Sixth Amendment”) of our amended and restated senior secured credit facility that permitted the sale of Elk Horn that was discussed earlier.

 

In December, 2016, we entered into the Seventh Amendment of our amended and restated credit agreement. The Seventh Amendment allows for the Series A preferred units discussed above. The Seventh Amendment immediately reduces the revolving credit commitments by $11.0 million and provides for additional revolving credit commitment reductions of $2.0 million each on June 30, 2017 and September 30, 2017. A condition precedent to the effectiveness of the Seventh Amendment was the receipt of the $13.0 million of cash proceeds received by us from the issuance of the Series A preferred units discussed above, which was used to repay outstanding borrowings under the revolving credit facility. Per the Seventh Amendment, the receipt of $13.0 million cash proceeds fulfills the required Royal equity contributions as outlined in the previous amendments to our credit agreement. (Please see “Part II, Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations—Liquidity and Capital Resources—Amended and Restated Credit Agreement” for further details on the debt amendments).

 

Delisting of Common Units from NYSE

 

On December 17, 2015, the New York Stock Exchange (“NYSE”) notified us that the NYSE had determined to commence proceedings to delist our common units from the NYSE as a result of our failure to comply with the continued listing standard set forth in Section 802.01B of the NYSE Listed Company Manual to maintain an average global market capitalization over a consecutive 30 trading-day period of at least $15 million for our common units. The NYSE also suspended the trading of our common units at the close of trading on December 17, 2015.

 

On January 4, 2016, we filed an appeal with the NYSE to review the suspension and delisting determination of our common units. The NYSE held a hearing regarding our appeal on April 20, 2016 and affirmed its prior decision to delist our common units.

 

On April 27, 2016, the NYSE filed with the SEC a notification of removal from listing and registration on Form 25 to delist our common units and terminate the registration of our common units under Section 12(b) of the Securities Exchange Act of 1934. The delisting became effective on May 9, 2016. Our common units trade on the OTCQB Marketplace under the ticker symbol “RHNO.”

 

We are exploring the possibility of listing our common units on the NASDAQ Stock Market (“NASDAQ”), pending our capability to meet the NASDAQ initial listing standards.

 

Reverse Unit Split

 

On April 18, 2016, we completed a 1-for-10 reverse split on our common units and subordinated units. Pursuant to the reverse split, common unitholders received one common unit for every 10 common units owned on April 18, 2016 and subordinated unitholders received one subordinated unit for every 10 subordinated units owned on April 18, 2016. Any fractional units resulting from the reverse unit split were rounded to the nearest whole unit. The reverse unit split was intended to increase the market price per unit of our common units in order to comply with the NYSE’s continued listing standards.

 

Distribution Suspension

 

Beginning with the quarter ended June 30, 2015 and continuing through the quarter ended December 31, 2016, we have suspended the cash distribution on our common units. For each of the quarters ended September 30, 2014, December 31, 2014 and March 31, 2015, we announced cash distributions per common unit at levels lower than the minimum quarterly distribution. We have not paid any distribution on our subordinated units for any quarter after the quarter ended March 31, 2012. The distribution suspension and prior reductions were the result of prolonged weakness in the coal markets, which has continued to adversely affect our cash flow.

 

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Pursuant to our partnership agreement, our common units accrue arrearages every quarter when the distribution level is below the minimum level of $4.45 per unit. Since our distributions for the quarters ended September 30, 2014, December 31, 2014 and March 31, 2015 were below the minimum level and we altogether suspended the distribution beginning with the quarters ended June 30, 2015 through December 31, 2016, we have accumulated arrearages at December 31, 2016 related to the common unit distribution of approximately $207.4 million.

 

History

 

Our predecessor was formed in April 2003 by Wexford Capital. We were formed in April 2010 to own and control the coal properties and related assets owned by Rhino Energy LLC. On October 5, 2010, we completed our IPO. Our common units were originally listed on the New York Stock Exchange under the symbol “RNO”. Please read “—Recent Developments—Delisting of Common Units from NYSE.” In connection with the IPO, Wexford contributed their membership interests in Rhino Energy LLC to us, and in exchange we issued subordinated units representing limited partner interests in us and common units to Wexford and issued incentive distribution rights to our general partner. In March 2016, Royal acquired our general partner and a majority limited partner interest in us from Wexford. Please read “—Recent Developments— Sale of our General Partner by Wexford.”

 

Since the formation of our predecessor in April 2003, we have completed numerous coal asset acquisitions with a total purchase price of approximately $357.5 million. Through these acquisitions and coal lease transactions, we have substantially increased our proven and probable coal reserves and non-reserve coal deposits. In addition, we have successfully grown our production through internal development projects. In addition to our coal acquisitions, in 2011 we began to invest in oil and natural gas assets and operations.

 

We are managed by the board of directors and executive officers of our general partner. Our operations are conducted through, and our operating assets are owned by, our wholly owned subsidiary, Rhino Energy LLC, and its subsidiaries.

 

Coal Operations

 

Mining and Leasing Operations

 

As of December 31, 2016, we operated two mining complexes located in Central Appalachia (Tug River and Rob Fork). In August 2016 we completed the sale of our Elk Horn coal leasing operation and in December 2015, we completed the sale of our Central Appalachia Deane mining complex (see Note 6 of the consolidated financial statements included elsewhere in this annual report for further information). In the third quarter of 2015, we temporarily idled a majority of our Central Appalachia operations due to ongoing weak coal market conditions for met and steam coal produced from this region. We resumed mining operations at all of our Central Appalachia operations in 2016 to fulfill customer contracts that we secured for 2016 and 2017.

 

In addition, we operated two mining complexes located in Northern Appalachia (Hopedale and Sands Hill). In the Western Bituminous region, we operated one mining complex located in Emery and Carbon Counties, Utah (Castle Valley). During 2014, we developed a new mining complex in the Illinois Basin, our Riveredge mine at our Pennyrile mining complex, which began production in mid-2014. The Pennyrile complex consists of one underground mine, a preparation plant and river loadout facility.

 

We define a mining complex as a central location for processing raw coal and loading coal into railroad cars, barges or trucks for shipment to customers. These mining complexes include seven active preparation plants and/or loadouts, each of which receive, blend, process and ship coal that is produced from one or more of our active surface and underground mines. All of the preparation plants are modern plants that have both coarse and fine coal cleaning circuits.

 

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The following map shows the location of our coal mining and leasing operations as of December 31, 2016 (Note: the McClane Canyon mine in Colorado was permanently idled at December 31, 2013):

 

 

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Our surface mines include area mining and contour mining. These operations use truck and wheel loader equipment fleets along with large production tractors and shovels. Our underground mines utilize the room and pillar mining method. These operations generally consist of one or more single or dual continuous miner sections which are made up of the continuous miner, shuttle cars, roof bolters, feeder and other support equipment. We currently own most of the equipment utilized in our mining operations. We employ preventive maintenance and rebuild programs to ensure that our equipment is modern and well-maintained. The rebuild programs are performed either by an on-site shop or by third-party manufacturers.

 

The following table summarizes our mining complexes and production by region as of December 31, 2016.

 

Region   Preparation
Plants and
Loadouts
  Transportation
to Customers(1)
 

Number and

Type of Active Mines(2)

   Tons Produced for the Year Ended
December 31,
2016 (3)
              (in million tons)
Central Appalachia               
Tug River Complex (KY, WV)   Tug Fork & Jamboree(4)  Truck, Barge, Rail (NS)   2S  0.4
Rob Fork Complex (KY)   Rob Fork  Truck, Barge, Rail (CSX)   1U,1S  0.3
Northern Appalachia            
Hopedale Complex (OH)   Nelms  Truck, Rail (OHC, WLE)   1U  0.3
Sands Hill Complex (OH)   Sands Hill(5)  Truck, Barge   1S  0.1
Illinois Basin            
Taylorville Field (IL)   n/a  Rail (NS)     
Pennyrile Complex (KY)   Preparation plant & river loadout  Barge   1U  1.3
Western Bituminous            
Castle Valley Complex (UT)   Truck loadout  Truck   1U  0.9
McClane Canyon Mine (CO)(6)   n/a  Truck     
Total          4U,4S  3.3

 

 

(1) NS = Norfolk Southern Railroad; CSX = CSX Railroad; OHC = Ohio Central Railroad; WLE = Wheeling & Lake Erie Railroad.
   
(2) Numbers indicate the number of active mines. U = underground; S = surface. All of our mines as of December 31, 2016 were company-operated.
   
(3) Total production based on actual amounts and not rounded amounts shown in this table.
   
(4) Jamboree includes only a loadout facility.
   
(5) Includes only a preparation plant.
   
(6) The McClane Canyon mine was permanently idled as of December 31, 2013.

 

Central Appalachia. For the year ended December 31, 2016, we operated two mining complexes located in Central Appalachia consisting of one active underground mine and three surface mines. For the year ended December 31, 2016, the mines at our Tug River and Rob Fork mining complexes produced an aggregate of approximately 0.4 million tons of steam coal and an estimated 0.3 million tons of metallurgical coal.

 

Tug River Mining Complex. Our Tug River mining complex is located in Kentucky and West Virginia bordering the Tug River. This complex produces coal from two company operated surface mines, which includes one high-wall mining unit. Coal production from these operations is delivered to the Tug Fork preparation plant for processing and then transported by truck to the Jamboree rail loadout for blending and shipping. Coal suitable for direct-ship to customers is delivered by truck directly to the Jamboree rail loadout from the mine sites. The Tug Fork plant is a modern, 350 tons per hour preparation plant utilizing heavy media circuitry that is capable of cleaning coarse and fine coal size fractions. The Jamboree loadout is located on the Norfolk Southern Railroad and is a modern unit train, batch weigh loadout. This mining complex produced approximately 0.3 million tons of steam coal and approximately 0.1 million tons of metallurgical coal for the year ended December 31, 2016.

 

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Rob Fork Mining Complex. Our Rob Fork mining complex is located in eastern Kentucky and produces coal from one company-operated surface mine and one company-operated underground mine. The Rob Fork mining complex is located on the CSX Railroad and consists of a modern preparation plant utilizing heavy media circuitry that is capable of cleaning coarse and fine coal size fractions and a unit train loadout with batch weighing equipment. The mining complex has significant blending capabilities allowing the blending of raw coals with washed coals to meet a wide variety of customers’ needs. The Rob Fork mining complex produced approximately 0.1 million tons of steam coal and 0.2 million tons of metallurgical coal for the year ended December 31, 2016.

 

Northern Appalachia. For the year ended December 31, 2016, we operated two mining complexes located in Northern Appalachia consisting of one company-operated underground mine and two company-operated surface mines. Coal mining at our Sands Hill complex are planned to cease during the second quarter of 2017 as market conditions for coal from this complex have continued to be weak. We will continue our limestone aggregate business at the Sands Hill complex for the next twelve to eighteen months as we have enough limestone inventory to process and sell for this time period. For the year ended December 31, 2016, these mines produced an aggregate of approximately 0.4 million tons of steam coal.

 

Hopedale Mining Complex. The Hopedale mining complex includes an underground mine located in Hopedale, Ohio approximately five miles northeast of Cadiz, Ohio. Coal produced from the Hopedale mine is first cleaned at our Nelms preparation plant located on the Ohio Central Railroad and the Wheeling & Lake Erie Railroad and then shipped by train or truck to our customers. The infrastructure includes a full-service loadout facility. This underground mining operation produced approximately 0.3 million tons of steam coal for the year ended December 31, 2016.

 

Sands Hill Mining Complex. We currently operate one surface mine at our Sands Hill mining complex, located near Hamden, Ohio, and we permanently idled the second surface mine at this complex during the second half of 2016. The infrastructure includes a preparation plant along with a river front barge and dock facility on the Ohio River. The Sands Hill mining complex produced approximately 0.1 million tons of steam coal and approximately 0.4 million tons of limestone aggregate for the year ended December 31, 2016.

 

Western Bituminous Region. We operate one mining complex in the Western Bituminous region that produces coal from an underground mine located in Emery and Carbon Counties, Utah. We also had one underground mine located in the Western Bituminous region in Colorado (McClane Canyon) that was permanently idled at the end of 2013.

 

Castle Valley Mining Complex. Our Castle Valley mining complex includes one underground mine located in Emery and Carbon Counties, Utah and include coal reserves and non-reserve coal deposits, underground mining equipment and infrastructure, an overland belt conveyor system, a loading facility and support facilities. We produced approximately 0.9 million tons of steam coal from one underground mine at this complex for the year ended December 31, 2016.

 

Illinois Basin. In May 2012, we completed the purchase of certain rights to coal leases and surface property that is contiguous to the Green River and located in Daviess and McLean counties in western Kentucky where we constructed a new underground mining complex. The property is fully permitted and provides us with access to Illinois Basin coal that is adjacent to a navigable waterway, which could allow for exports to non-U.S. customers. During 2014, we completed the initial construction of a new underground mining operation on this property. Production began in late May 2014 and the first barge shipments of coal departed from this facility in early July 2014. We have sales contracts with local electric utility customers and we have other potential customers that we believe could lead to additional long-term sales agreements if we can successfully expand our production capacity at this operation.

 

Pennyrile Mining Complex. In mid-2014, we completed the initial construction of a new underground mining operation on the purchased property, referred to as our Pennyrile mining complex, which includes one underground mine, a preparation plant and river loadout facility. Production from this underground mine began in mid-2014 and we produced approximately 1.3 million tons for the year ended December 31, 2016. We believe the possibility exists to expand production up to 2.0 million tons per year with further development of the mine at the Pennyrile complex.

 

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Other Non-Mining Operations

 

In addition to our mining operations, we operate several subsidiaries which provide auxiliary services for our coal mining operations. Rhino Trucking provides our southeastern Ohio coal operations with reliable transportation to our customers where rail is not available. Rhino Services is responsible for mine-related construction, site and roadway maintenance and post-mining reclamation. Through Rhino Services, we plan and monitor each phase of our mining projects as well as the post-mining reclamation efforts. We also perform the majority of our drilling and blasting activities at our company-operated surface mines in-house rather than contracting to a third party.

 

Other Natural Resource Assets

 

Oil and Natural Gas

 

In addition to our coal operations, we have invested in oil and natural gas assets and operations.

 

In September 2014, we made an initial investment of $5.0 million in a new joint venture, Sturgeon Acquisitions LLC (“Sturgeon”), with affiliates of Wexford Capital and Gulfport Energy (“Gulfport”). Sturgeon subsequently acquired 100% of the outstanding equity interests of certain limited liability companies located in Wisconsin that provide frac sand for oil and natural gas drillers in the United States. We account for the investment in this joint venture and results of operations under the equity method. We recorded our proportionate portion of the operating (losses)/gains for this investment during 2016 and 2015 of approximately ($0.2) million and $0.3 million, respectively.

 

In November 2014, we contributed our investment interest in a joint venture, Muskie Proppant LLC (“Muskie”) with affiliates of Wexford Capital that was formed to provide sand for fracking operations to drillers in the Utica Shale Region and other oil and natural gas basins in the United States to Mammoth Energy Partners LP (“Mammoth”) in return for a limited partner interest in Mammoth. Mammoth was formed to provide services to companies, which engage in the exploration and development of North American onshore unconventional oil and natural gas reserves. Mammoth provides services that include completion and production services, contract land and directional drilling services and remote accommodation services. The non-cash transaction was a contribution of our investment interest in the Muskie entity for an investment interest in Mammoth. Thus, we determined that the non-cash exchange of our ownership interest in Muskie did not result in any gain or loss. As of December 31, 2015, we recorded our investment in Mammoth of $1.9 million as a long-term asset, which we recorded as a cost method investment based upon our ownership percentage. In October 2016, we contributed our limited partner interests in Mammoth to Mammoth Energy Services, Inc. (“Mammoth Inc.”) in exchange for 234,300 shares of common stock of Mammoth Inc. The common stock of Mammoth Inc. began trading on the NASDAQ Global Select Market in October 2016 under the ticker symbol TUSK and we sold 1,953 shares during the initial public offering of Mammoth Inc. and received proceeds of approximately $27,000. Our remaining shares of Mammoth Inc. are subject to a 180 day lock-up period from the date of Mammoth Inc.’s initial public offering. As of December 31, 2016, we recorded a fair market value adjustment of $1.6 million for the available-for-sale investment, which was recorded in other comprehensive income. We have included our investment in Mammoth and our prior investment in Muskie in our Other category for segment reporting purposes.

 

Limestone

 

Incidental to our coal mining process, we mine limestone from reserves located at our Sands Hill mining complex and sell it as aggregate to various construction companies and road builders that are located in close proximity to the mining complex when market conditions are favorable. We believe that our production of limestone provides us with an additional source of revenues at low incremental capital cost for the next twelve to eighteen months.

 

Coal Customers

 

General

 

Our primary customers for our steam coal are electric utilities, and the metallurgical coal we produce is sold primarily to domestic and international steel producers. For the year ended December 31, 2016, approximately 90.0% of our coal sales tons consisted of steam coal and approximately 10.0% consisted of metallurgical coal. For the year ended December 31, 2016, approximately 83.0% of our coal sales tons that we produced were sold to electric utilities. The majority of our electric utility customers purchase coal for terms of one to three years, but we also supply coal on a spot basis for some of our customers. For the year ended December 31, 2016, we derived approximately 87.4% of our total coal revenues from sales to our ten largest customers, with affiliates of our top three customers accounting for approximately 48.5% of our coal revenues for that period: PPL Corporation (26.2%); PacificCorp Energy (12.2%); and Big Rivers (10.1%). Incidental to our coal mining process, we mine limestone and sell it as aggregate to various construction companies and road builders that are located in close proximity to our Sands Hill mining complex.

 

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Coal Supply Contracts

 

For the years ended December 31, 2016 and 2015, approximately 90% and 84%, respectively, of our aggregate coal tons sold were sold through supply contracts. We expect to continue selling a significant portion of our coal under supply contracts. As of December 31, 2016, we had commitments under supply contracts to deliver annually scheduled base quantities as follows:

 

Year  Tons (in thousands)   Number of customers 
2017   3,669    14 
2018   701    5 

 

Some of the contracts have sales price adjustment provisions, subject to certain limitations and adjustments, based on a variety of factors and indices.

 

Quality and volumes for the coal are stipulated in coal supply contracts, and in some instances buyers have the option to vary annual or monthly volumes. Most of our coal supply contracts contain provisions requiring us to deliver coal within certain ranges for specific coal characteristics such as heat content, sulfur, ash, hardness and ash fusion temperature. Failure to meet these specifications can result in economic penalties, suspension or cancellation of shipments or termination of the contracts. Some of our contracts specify approved locations from which coal may be sourced. Some of our contracts set out mechanisms for temporary reductions or delays in coal volumes in the event of a force majeure, including events such as strikes, adverse mining conditions, mine closures, or serious transportation problems that affect us or unanticipated plant outages that may affect the buyers.

 

The terms of our coal supply contracts result from competitive bidding procedures and extensive negotiations with customers. As a result, the terms of these contracts, including price adjustment features, price re-opener terms, coal quality requirements, quantity parameters, permitted sources of supply, future regulatory changes, extension options, force majeure, termination and assignment provisions, vary significantly by customer.

 

Transportation

 

We ship coal to our customers by rail, truck or barge. The majority of our coal is transported to customers by either the CSX Railroad or the Norfolk Southern Railroad in eastern Kentucky and by the Ohio Central Railroad or the Wheeling & Lake Erie Railroad in Ohio. In addition, in southeastern Ohio, we use our own trucking operations to transport coal to our customers where rail is not available. We use third-party trucking to transport coal to our customers in Utah. For our Pennyrile complex in western Kentucky, coal is transported to our customers via barge from our river loadout on the Green River located on our Pennyrile mining complex. In addition, coal from certain of our Central Appalachia and southern Ohio mines is located within economical trucking distance to the Big Sandy River and/or the Ohio River and can be transported by barge. It is customary for customers to pay the transportation costs to their location.

 

We believe that we have good relationships with rail carriers, barge companies and truck companies due, in part, to our modern coal-loading facilities at our loadouts and the working relationships and experience of our transportation and distribution employees.

 

Suppliers

 

Principal supplies used in our business include diesel fuel, explosives, maintenance and repair parts and services, roof control and support items, tires, conveyance structures, ventilation supplies and lubricants. We use third-party suppliers for a significant portion of our equipment rebuilds and repairs, drilling services and construction.

 

We have a centralized sourcing group for major supplier contract negotiation and administration, for the negotiation and purchase of major capital goods and to support the mining and coal preparation plants. We are not dependent on any one supplier in any region. We promote competition between suppliers and seek to develop relationships with those suppliers whose focus is on lowering our costs. We seek suppliers who identify and concentrate on implementing continuous improvement opportunities within their area of expertise.

 

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Competition

 

The coal industry is highly competitive. There are numerous large and small producers in all coal producing regions of the United States and we compete with many of these producers. Our main competitors include Alliance Resource Partners LP, Alpha Natural Resources, Inc., Arch Coal, Inc., Booth Energy Group, Murray Energy Corporation, Foresight Energy LP, Westmoreland Resource Partners, LP and Bowie Resource Partners LLC.

 

The most important factors on which we compete are coal price, coal quality and characteristics, transportation costs and the reliability of supply. Demand for coal and the prices that we will be able to obtain for our coal are closely linked to coal consumption patterns of the domestic electric generation industry and international consumers. These coal consumption patterns are influenced by factors beyond our control, including demand for electricity, which is significantly dependent upon economic activity and summer and winter temperatures in the United States, government regulation, technological developments and the location, availability, quality and price of competing sources of fuel such as natural gas, oil and nuclear, and alternative energy sources such as hydroelectric power and wind power.

 

Regulation and Laws

 

Our operations are subject to regulation by federal, state and local authorities on matters such as:

 

  employee health and safety;
     
  governmental approvals and other authorizations such as mine permits, as well as other licensing requirements;
     
  air quality standards;
     
  water quality standards;
     
  storage, treatment, use and disposal of petroleum products and other hazardous substances;
     
  plant and wildlife protection;
     
  reclamation and restoration of mining properties after mining is completed;
     
  the discharge of materials into the environment, including waterways or wetlands;
     
  storage and handling of explosives;
     
  wetlands protection;
     
  surface subsidence from underground mining;
     
  the effects, if any, that mining has on groundwater quality and availability; and
     
  legislatively mandated benefits for current and retired coal miners.

 

In addition, many of our customers are subject to extensive regulation regarding the environmental impacts associated with the combustion or other use of coal, which could affect demand for our coal. The possibility exists that new laws or regulations, or new interpretations of existing laws or regulations, may be adopted that may have a significant impact on our mining operations, oil and natural gas investments, or our customers’ ability to use coal. Moreover, environmental citizen groups frequently challenge coal mining, terminal construction, and other related projects.

 

We are committed to conducting mining operations in compliance with applicable federal, state and local laws and regulations. However, because of extensive and comprehensive regulatory requirements, violations during mining operations occur from time to time. Violations, including violations of any permit or approval, can result in substantial civil and in severe cases, criminal fines and penalties, including revocation or suspension of mining permits. None of the violations to date have had a material impact on our operations or financial condition.

 

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While it is not possible to quantify the costs of compliance with applicable federal and state laws and regulations, those costs have been and are expected to continue to be significant. Nonetheless, capital expenditures for environmental matters have not been material in recent years. We have accrued for the present value of estimated cost of reclamation and mine closings, including the cost of treating mine water discharge when necessary. The accruals for reclamation and mine closing costs are based upon permit requirements and the costs and timing of reclamation and mine closing procedures. Although management believes it has made adequate provisions for all expected reclamation and other costs associated with mine closures, future operating results would be adversely affected if we later determined these accruals to be insufficient. Compliance with these laws and regulations has substantially increased the cost of coal mining for all domestic coal producers. Most of the statutes discussed below apply to exploration and development activities associated with our oil and natural gas investments as well, and therefore we do not present a separate discussion of statutes related to those activities.

 

Mining Permits and Approvals

 

Numerous governmental permits or approvals are required for coal mining operations. When we apply for these permits and approvals, we are often required to assess the effect or impact that any proposed production of coal may have upon the environment. Final guidance released by the CEQ regarding climate change considerations in the NEPA analyses may increase the likelihood of future challenges to the NEPA documents prepared for actions requiring federal approval. The permit application requirements may be costly and time consuming, and may delay or prevent commencement or continuation of mining operations in certain locations. In addition, these permits and approvals can result in the imposition of numerous restrictions on the time, place and manner in which coal mining operations are conducted. Future laws and regulations may emphasize more heavily the protection of the environment and, as a consequence, our activities may be more closely regulated. Laws and regulations, as well as future interpretations or enforcement of existing laws and regulations, may require substantial increases in equipment and operating costs, or delays, interruptions or terminations of operations, the extent of any of which cannot be predicted. For example, in January 2016, the federal Bureau of Land Management announced a moratorium on new coal leases for federal lands. The moratorium does not affect existing leases. In addition, the permitting process for certain mining operations can extend over several years, and can be subject to judicial challenge, including by the public. Some required mining permits are becoming increasingly difficult to obtain in a timely manner, or at all. We may experience difficulty and/or delay in obtaining mining permits in the future.

 

Regulations provide that a mining permit can be refused or revoked if the permit applicant or permittee owns or controls, directly or indirectly through other entities, mining operations which have outstanding environmental violations. Although, like other coal companies, we have been cited for violations in the ordinary course of business, we have never had a permit suspended or revoked because of any violation, and the penalties assessed for these violations have not been material.

 

Before commencing mining on a particular property, we must obtain mining permits and approvals by state regulatory authorities of a reclamation plan for restoring, upon the completion of mining, the mined property to its approximate prior condition, productive use or other permitted condition.

 

Mine Health and Safety Laws

 

Stringent safety and health standards have been in effect since the adoption of the Coal Mine Health and Safety Act of 1969. The Federal Mine Safety and Health Act of 1977 (the “Mine Act”), and regulations adopted pursuant thereto, significantly expanded the enforcement of health and safety standards and imposed comprehensive safety and health standards on numerous aspects of mining operations, including training of mine personnel, mining procedures, blasting, the equipment used in mining operations and other matters. The Mine Safety and Health Administration (“MSHA”) monitors compliance with these laws and regulations. In addition, the states where we operate also have state programs for mine safety and health regulation and enforcement. Federal and state safety and health regulations affecting the coal industry are complex, rigorous and comprehensive, and have a significant effect on our operating costs.

 

The Mine Act is a strict liability statute that requires mandatory inspections of surface and underground coal mines and requires the issuance of enforcement action when it is believed that a standard has been violated. A penalty is required to be imposed for each cited violation. Negligence and gravity assessments result in a cumulative enforcement scheme that may result in the issuance of an order requiring the immediate withdrawal of miners from the mine or shutting down a mine or any section of a mine or any piece of mine equipment. The Mine Act contains criminal liability provisions. For example, criminal liability may be imposed for corporate operators who knowingly or willfully authorize, order or carry out violations. The Mine Act also provides that civil and criminal penalties may be assessed against individual agents, officers and directors who knowingly authorize, order or carry out violations.

 

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We have developed a health and safety management system that, among other things, includes training regarding worker health and safety requirements including those arising under federal and state laws that apply to our mines. In addition, our health and safety management system tracks the performance of each operational facility in meeting the requirements of safety laws and company safety policies. As an example of the resources we allocate to health and safety matters, our safety management system includes a company-wide safety director and local safety directors who oversee safety and compliance at operations on a day-to-day basis. We continually monitor the performance of our safety management system and from time-to-time modify that system to address findings or reflect new requirements or for other reasons. We have even integrated safety matters into our compensation and retention decisions. For instance, our bonus program includes a meaningful evaluation of each eligible employee’s role in complying with, fostering and furthering our safety policies.

 

We evaluate a variety of safety-related metrics to assess the adequacy and performance of our safety management system. For example, we monitor and track performance in areas such as “accidents, reportable accidents, lost time accidents and the lost-time accident frequency rate” and a number of others. Each of these metrics provides insights and perspectives into various aspects of our safety systems and performance at particular locations or mines generally and, among other things, can indicate where improvements are needed or further evaluation is warranted with regard to the system or its implementation. An important part of this evaluation is to assess our performance relative to certain national benchmarks.

 

For the year ended December 31, 2016 our average MSHA violations per inspection day was 0.25 as compared to the most recent national average of 0.67 violations per inspection day for coal mining activity as reported by MSHA, or 62.69% below this national average.

 

Mining accidents in the last several years in West Virginia, Kentucky and Utah have received national attention and instigated responses at the state and national levels that have resulted in increased scrutiny of current safety practices and procedures at all mining operations, particularly underground mining operations. For example, in 2014, MSHA adopted a final rule to lower miners’ exposure to respirable coal mine dust. The rule had a phased implementation schedule. The second phase of the rule went into effect in February 2016, and requires increased sampling frequency and the use of continuous personal dust monitors. In August 2016, the third and final phase of the rule became effective, reducing the overall respirable dust standard in coal mines from 2.0 to 1.5 milligrams per cubic meter of air. Additionally, in September 2015, MSHA issued a proposed rule requiring the installation of proximity detection systems on coal hauling machines and scoops. Proximity detection is a technology that uses electronic sensors to detect motion and the distance between a miner and a machine. These systems provide audible and visual warnings, and automatically stop moving machines when miners are in the machines’ path. These and other new safety rules could result in increased compliance costs on our operations.

 

In addition, more stringent mine safety laws and regulations promulgated by these states and the federal government have included increased sanctions for non-compliance. For example, in 2006, the Mine Improvement and New Emergency Response Act of 2006, or MINER Act, was enacted. The MINER Act significantly amended the Mine Act, requiring improvements in mine safety practices, increasing criminal penalties and establishing a maximum civil penalty for non-compliance, and expanding the scope of federal oversight, inspection and enforcement activities. Since passage of the MINER Act in 2006, enforcement scrutiny has increased, including more inspection hours at mine sites, increased numbers of inspections and increased issuance of the number and the severity of enforcement actions and related penalties. For example, in July 2014, MSHA proposed a rule that revises its civil penalty assessment provisions and how regulators should approach calculating penalties, which, in some instances, could result in increased civil penalty assessments for medium and larger mine operators and contractors by 300 to 1,000 percent. MSHA proposed some revisions to the original proposed rule in February 2015, but, to date, has not taken any further action. Other states have proposed or passed similar bills, resolutions or regulations addressing enhanced mine safety practices and increased fines and penalties. Moreover, workplace accidents, such as the April 5, 2010, Upper Big Branch Mine incident, have resulted in more inspection hours at mine sites, increased number of inspections and increased issuance of the number and severity of enforcement actions and the passage of new laws and regulations. These trends are likely to continue.

 

Indeed, in 2013, MSHA began implementing its recently released Pattern of Violation (“POV”) regulations under the Mine Act. Under this regulation, MSHA eliminated the ninety (90) day window to take corrective action and engage in mitigation efforts for mine operators who met certain initial POV screening criteria. Additionally, MSHA will make POV determinations based upon enforcement actions as issued, rather than enforcement actions that have been rendered final following the opportunity for administrative or judicial review. After a mine operator has been placed on POV status, MSHA will thereafter issue an order withdrawing miners from the area affected by any enforcement action designated by MSHA as posing a significant and substantial, or S&S, hazard to the health and/or safety of miners. Further, once designated as a POV mine, a mine operator can be removed from POV status only upon: (1) a complete inspection of the entire mine with no S&S enforcement actions issued by MSHA; or (2) no POV-related withdrawal orders being issued by MSHA within ninety (90) days of the mine operator being placed on POV status. Although it remains to be seen how these new regulations will ultimately affect production at our mines, they are consistent with the trend of more stringent enforcement.

 

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From time to time, certain portions of individual mines have been required to suspend or shut down operations temporarily in order to address a compliance requirement or because of an accident. For instance, MSHA issues orders pursuant to Section 103(k) that, among other things, call for operations in the area of the mine at issue to suspend operations until compliance is restored. Likewise, if an accident occurs within a mine, the MSHA requirements call for all operations in that area to be suspended until the circumstance leading to the accident has been resolved. During the fiscal year ended December 31, 2016 (as in earlier years), we received such orders from government agencies and have experienced accidents within our mines requiring the suspension or shutdown of operations in those particular areas until the circumstances leading to the accident have been resolved. While the violations or other circumstances that caused such an accident were being addressed, other areas of the mine could and did remain operational. These circumstances did not require us to suspend operations on a mine-wide level or otherwise entail material financial or operational consequences for us. Any suspension of operations at any one of our locations that may occur in the future may have material financial or operational consequences for us.

 

It is our practice to contest notices of violations in cases in which we believe we have a good faith defense to the alleged violation or the proposed penalty and/or other legitimate grounds to challenge the alleged violation or the proposed penalty. We exercise substantial efforts toward achieving compliance at our mines. For example, we have further increased our focus with regard to health and safety at all of our mines. These efforts include hiring additional skilled personnel, providing training programs, hosting quarterly safety meetings with MSHA personnel and making capital expenditures in consultation with MSHA aimed at increasing mine safety. We believe that these efforts have contributed, and continue to contribute, positively to safety and compliance at our mines. In “Part 1, Item 4. Mine Safety Disclosure” and in Exhibit 95.1 to this Annual Report on Form 10-K, we provide additional details on how we monitor safety performance and MSHA compliance, as well as provide the mine safety disclosures required pursuant to Section 1503(a) of the Dodd-Frank Wall Street Reform and Consumer Protection Act.

 

Black Lung Laws

 

Under the Black Lung Benefits Act of 1977 and the Black Lung Benefits Reform Act of 1977, as amended in 1981, coal mine operators must make payments of black lung benefits to current and former coal miners with black lung disease, some survivors of a miner who dies from this disease, and to fund a trust fund for the payment of benefits and medical expenses to claimants who last worked in the industry prior to January 1, 1970. To help fund these benefits, a tax is levied on production of $1.10 per ton for underground-mined coal and $0.55 per ton for surface-mined coal, but not to exceed 4.4% of the applicable sales price. This excise tax does not apply to coal that is exported outside of the United States. In 2016, we recorded approximately $3.0 million of expense related to this excise tax.

 

The Patient Protection and Affordable Care Act includes significant changes to the federal black lung program including an automatic survivor benefit paid upon the death of a miner with an awarded black lung claim and establishes a rebuttable presumption with regard to pneumoconiosis among miners with 15 or more years of coal mine employment that are totally disabled by a respiratory condition. These changes could have a material impact on our costs expended in association with the federal black lung program. We may also be liable under state laws for black lung claims that are covered through either insurance policies or state programs.

 

Workers’ Compensation

 

We are required to compensate employees for work-related injuries under various state workers’ compensation laws. The states in which we operate consider changes in workers’ compensation laws from time to time. Our costs will vary based on the number of accidents that occur at our mines and other facilities, and our costs of addressing these claims. We are insured under the Ohio State Workers Compensation Program for our operations in Ohio. Our remaining operations, including Central Appalachia and the Western Bituminous region, are insured through Rockwood Casualty Insurance Company.

 

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Surface Mining Control and Reclamation Act (“SMCRA”)

 

SMCRA establishes operational, reclamation and closure standards for all aspects of surface mining, including the surface effects of underground coal mining. SMCRA requires that comprehensive environmental protection and reclamation standards be met during the course of and upon completion of mining activities. In conjunction with mining the property, we reclaim and restore the mined areas by grading, shaping and preparing the soil for seeding. Upon completion of mining, reclamation generally is completed by seeding with grasses or planting trees for a variety of uses, as specified in the approved reclamation plan. We believe we are in compliance in all material respects with applicable regulations relating to reclamation.

 

SMCRA and similar state statutes require, among other things, that mined property be restored in accordance with specified standards and approved reclamation plans. The act requires that we restore the surface to approximate the original contours as soon as practicable upon the completion of surface mining operations. The mine operator must submit a bond or otherwise secure the performance of these reclamation obligations. Mine operators can also be responsible for replacing certain water supplies damaged by mining operations and repairing or compensating for damage to certain structures occurring on the surface as a result of mine subsidence, a consequence of long-wall mining and possibly other mining operations. In addition, the Abandoned Mine Lands Program, which is part of SMCRA, imposes a tax on all current mining operations, the proceeds of which are used to restore mines closed prior to SMCRA’s adoption in 1977. The maximum tax for the period from October 1, 2012 through September 30, 2021, has been decreased to 28 cents per ton on surface mined coal and 12 cents per ton on underground mined coal. However, this fee is subject to change. The President’s Budget for Fiscal Year 2017 proposes to restore fees on coal production to pre-2006 levels in order to fund the reclamation of abandoned mines. If enacted into law, this proposal would increase the fees on surface mining to $0.35 per ton and increase the fees on underground mining to $0.15 per ton. Given the market for coal, it is unlikely that coal mining companies would be able to recover all of these fees from their customers. As of December 31, 2016, we had accrued approximately $23.3 million for the estimated costs of reclamation and mine closing, including the cost of treating mine water discharge when necessary. In addition, states from time to time have increased and may continue to increase their fees and taxes to fund reclamation of orphaned mine sites and abandoned mine drainage control on a statewide basis.

 

After a mine application is submitted, public notice or advertisement of the proposed permit action is required, which is followed by a public comment period. It is not uncommon for a SMCRA mine permit application to take over two years to prepare and review, depending on the size and complexity of the mine, and another two years or even longer for the permit to be issued. The variability in time frame required to prepare the application and issue the permit can be attributed primarily to the various regulatory authorities’ discretion in the handling of comments and objections relating to the project received from the general public and other agencies. Also, it is not uncommon for a permit to be delayed as a result of judicial challenges related to the specific permit or another related company’s permit.

 

Federal laws and regulations also provide that a mining permit or modification can be delayed, refused or revoked if owners of specific percentages of ownership interests or controllers (i.e., officers and directors or other entities) of the applicant have, or are affiliated with another entity that has outstanding violations of SMCRA or state or tribal programs authorized by SMCRA. This condition is often referred to as being “permit blocked” under the federal Applicant Violator Systems, or AVS. Thus, non-compliance with SMCRA can provide the bases to deny the issuance of new mining permits or modifications of existing mining permits, although we know of no basis by which we would be (and we are not now) permit-blocked.

 

In addition, a February 2014 decision by the U.S. District Court for the District of Columbia invalidated the Office of Surface Mining Reclamation and Enforcement’s (“OSM”) 2008 Stream Buffer Zone Rule, which prohibited mining disturbances within 100 feet of streams, subject to various exemptions. In December 2016, the OSM published the final Stream Protection Rule, which, among other things, would require operators to test and monitor conditions of streams they might impact before, during and after mining. The final rule took effect in January 2017 and would have required mine operators to collect additional baseline data about the site of the proposed mining operation and adjacent areas; imposed additional surface and groundwater monitoring requirements; enacted specific requirements for the protection or restoration of perennial and intermittent streams; and imposed additional bonding and financial assurance requirements. However, in February 2017, both the House and the Senate passed measures to revoke the Stream Protection Rule under the Congressional Review Act (“CRA”), which gives Congress the ability to repeal regulations promulgated in the last 60 days of the congressional session. President Trump signed the resolution on February 16, 2017 and, pursuant to the CRA, the Stream Protection Rule “shall have no force or effect” and OSM cannot promulgate a substantially similar rule absent future legislation. Whether Congress will enact future legislation to require a new Stream Protection Rule remains uncertain. A new Stream Protection Rule, or other new SMCRA regulations, could result in additional material costs, obligations, and restrictions associated with our operations.

 

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Surety Bonds

 

Federal and state laws require a mine operator to secure the performance of its reclamation obligations required under SMCRA through the use of surety bonds or other approved forms of performance security to cover the costs the state would incur if the mine operator were unable to fulfill its obligations. It has become increasingly difficult for mining companies to secure new surety bonds without the posting of partial collateral. In August 2016, the OSMRE issued a Policy Advisory discouraging state regulatory authorities from approving self-bonding arrangements. The Policy Advisory indicated that the OSM would begin more closely reviewing instances in which states accept self-bonds for mining operations. In the same month, the OSM also announced that it was beginning the rulemaking process to strengthen regulations on self-bonding. In addition, surety bond costs have increased while the market terms of surety bond have generally become less favorable. It is possible that surety bonds issuers may refuse to renew bonds or may demand additional collateral upon those renewals. Our failure to maintain, or inability to acquire, surety bonds that are required by state and federal laws would have a material adverse effect on our ability to produce coal, which could affect our profitability and cash flow.

 

As of December 31, 2016, we had approximately $48.9 million in surety bonds outstanding to secure the performance of our reclamation obligations. We may be required to increase these amounts as a result of recent developments in West Virginia and Kentucky. In 2011, West Virginia passed legislation that provides for a minimum incremental bonding rate in lieu of a minimum bond amount that applies regardless of acreage. In addition, the Kentucky Department for Natural Resources and the Office of Surface Mining Reclamation and Enforcement Lexington Field Office executed an Action Plan for Improving the Adequacy of Kentucky Performance Bond Amounts, which provides for, among other things, revised bond computation protocols.

 

Air Emissions

 

The federal Clean Air Act (the “CAA”) and similar state and local laws and regulations, which regulate emissions into the air, affect coal mining operations both directly and indirectly. The CAA directly impacts our coal mining and processing operations by imposing permitting requirements and, in some cases, requirements to install certain emissions control equipment, on sources that emit various hazardous and non-hazardous air pollutants. The CAA also indirectly affects coal mining operations by extensively regulating the air emissions of coal-fired electric power generating plants and other industrial consumers of coal, including air emissions of sulfur dioxide, nitrogen oxides, particulates, mercury and other compounds. There have been a series of recent federal rulemakings from the U.S. Environmental Protection Agency, or EPA, which are focused on emissions from coal-fired electric generating facilities. For example, In June 2015, the United States Supreme Court decided Michigan v. the EPA, which held that the EPA should have considered the compliance costs associated with its Mercury and Air Toxics Standards, or MATS, in deciding to regulate power plants under Section 112(n)(1) of the Clean Air Act. The Court did not vacate the MATS rule, and MATS has remained in place. In April 2016, EPA published its final supplemental finding that it is “appropriate and necessary” to regulate coal and oil-fired units under Section 112 of the Clean Air Act. In August 2016, EPA denied two petitions for reconsideration of startup and shutdown provisions in MATS, leaving in place the startup and shutdown provisions finalized in November 2014. The MATS rule was expected to result in the retirement of certain older coal plants. It remains to be seen whether any power plants may reevaluate their decision to retire following the Supreme Court’s decision and EPA’s recent actions, or whether plants that have already installed certain controls to comply with MATS will continue to operate them at all times. Installation of additional emissions control technology and additional measures required under laws and regulations related to air emissions will make it more costly to operate coal-fired power plants and possibly other facilities that consume coal and, depending on the requirements of individual state implementation plans, or SIPs, could make coal a less attractive fuel alternative in the planning and building of power plants in the future.

 

In addition to the greenhouse gas (“GHG”) regulations discussed below, air emission control programs that affect our operations, directly or indirectly, through impacts to coal-fired utilities and other manufacturing plants, include, but are not limited to, the following:

 

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  The EPA’s Acid Rain Program, provided in Title IV of the CAA, regulates emissions of sulfur dioxide from electric generating facilities. Sulfur dioxide is a by-product of coal combustion. Affected facilities purchase or are otherwise allocated sulfur dioxide emissions allowances, which must be surrendered annually in an amount equal to a facility’s sulfur dioxide emissions in that year. Affected facilities may sell or trade excess allowances to other facilities that require additional allowances to offset their sulfur dioxide emissions. In addition to purchasing or trading for additional sulfur dioxide allowances, affected power facilities can satisfy the requirements of the EPA’s Acid Rain Program by switching to lower sulfur fuels, installing pollution control devices such as flue gas desulfurization systems, or “scrubbers,” or by reducing electricity generating levels.
     
  On July 6, 2011, the EPA finalized the Cross State Air Pollution Rule (“CSAPR”), which requires the District of Columbia and 27 states from Texas eastward (not including the New England states or Delaware) to significantly improve air quality by reducing power plant emissions that cross state lines and contribute to ozone and/or fine particle pollution in other states. Under the CSAPR, the first phase of the nitrogen oxide and sulfur dioxide emissions reductions was to commence in 2012 with further reductions effective in 2014. In October 2011, the EPA proposed amendments to the CSAPR to increase emission budgets in ten states, including Texas, and ease limits on market-based compliance options. While the CSAPR had an initial compliance deadline of January 1, 2012, the rule was challenged and, on December 30, 2011, the D.C. Circuit stayed the rule and advised that the EPA was expected to continue administering the Clean Air Interstate Rule until the pending challenges are resolved. The court vacated the CSAPR on August 21, 2012, in a two to one decision, concluding that the rule was beyond the EPA’s statutory authority. The U.S. Supreme Court on April 29, 2014 reversed the D.C. Circuit and upheld the CSAPR, concluding generally that the EPA’s development and promulgation of CSAPR was lawful, while acknowledging the possibility that under certain circumstances some states may have a basis to bring a particularized, as-applied challenge to the rule. In October 2014, the D.C. Circuit filed an order lifting its stay of CSAPR and addressing a number of preliminary motions regarding the implementation of the Supreme Court’s remand. On remand, the D.C. Circuit court held on July 28, 2015 that certain of EPA’s Phase II emission budgets were invalid because they required more emissions reductions than necessary to achieve the desired air pollutant reduction in the relevant downwind states. The court did not vacate the rule but required the EPA to reconsider the invalid emissions budgets. In September 2016, EPA finalized the CSAPR Rule Update for the 2008 ozone NAAQS. Starting in May 2017, the rule will reduce summertime NOx emissions from power plants in 22 states in the eastern United States.
     
  In addition, in January 2013, the EPA issued final MACT standards for several classes of boilers and process heaters, including large coal-fired boilers and process heaters (Boiler MACT), which require significant reductions in the emission of particulate matter, carbon monoxide, hydrogen chloride, dioxins and mercury. Business and environmental groups have filed legal challenges in federal appeals court and have petitioned EPA to reconsider the rule. EPA has granted petitions for reconsideration for certain issues and promulgated a revised final rule in November 2015. The EPA retained a minimum carbon monoxide limit of 130 parts per million and the particulate matter continuous parameter monitoring system requirements, consistent with the January 2013 final rule, but made some minor changes to provisions related to boiler startup and shutdown practices. In July 2016, the D.C. Circuit issued a ruling on the consolidated cases challenging Boiler MACT, vacating key portions of the rule, including emission limits for certain subcategories of solid fuel boilers, and remanding other issues to the EPA for further rulemaking. In December 2016, the court issued a decision denying a full panel rehearing and remanding without vacating the numeric MACT standards set in the Major Boilers Rule for new and existing sources in each of the 18 subcategories. Certiorari petitions are likely. We cannot predict the outcome of any legal challenges that may be filed in the future, however, if Boiler MACT is upheld as previously finalized, EPA estimates the rule will affect 1,700 existing major source facilities with an estimated 14,316 boilers and process heaters. Some owners will make capital expenditures to retrofit boilers and process heaters, while a number of boilers and process heaters will be prematurely retired. The retirements are likely to reduce the demand for coal. The impact of the regulations will depend on the outcome of future legal challenges and EPA actions cannot be determined at this time.
     
  The EPA has adopted new, more stringent national air quality standards (“NAAQS”) for ozone, fine particulate matter, nitrogen dioxide and sulfur dioxide. As a result, some states will be required to amend their existing SIPs to attain and maintain compliance with the new air quality standards. For example, in June 2010, the EPA issued a final rule setting forth a more stringent primary NAAQS applicable to sulfur dioxide. The rule also modifies the monitoring increment for the sulfur dioxide standard, establishing a 1-hour standard, and expands the sulfur dioxide monitoring network. Initial non-attainment determinations related to the 2010 sulfur dioxide rule were published in August 2013 with an effective date in October 2013. States with non-attainment areas had to submit their SIP revisions in April 2015, which must meet the modified standard by summer 2017. For all other areas, states will be required to submit “maintenance” SIPs. EPA finalized its PM2.5 NAAQS designations in December 2014. Individual states must now identify the sources of PM2.5 emissions and develop emission reduction plans, which may be state-specific or regional in scope. Nonattainment areas must meet the revised standard no later than 2021. More recently, in October 2015, the EPA lowered the NAAQS for ozone from 75 to 70 parts per billion for both the 8-hour primary and secondary standards. Significant additional emissions control expenditures will likely be required at coal-fired power plants and coke plants to meet the new standards. Because coal mining operations and coal-fired electric generating facilities emit particulate matter and sulfur dioxide, our mining operations and customers could be affected when the standards are implemented by the applicable states. Moreover, we could face adverse impacts on our business to the extent that these and any other new rules affecting coal-fired power plants result in reduced demand for coal.

 

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  In June 2005, the EPA amended its regional haze program to improve visibility in national parks and wilderness areas. Affected states were required to develop SIPs by December 2007 that, among other things, identify facilities that will have to reduce emissions and comply with stricter emission limitations. Implementation of this program may restrict construction of new coal-fired power plants where emissions are projected to reduce visibility in protected areas. In addition, this program may require certain existing coal-fired power plants to install emissions control equipment to reduce haze-causing emissions such as sulfur dioxide, nitrogen oxide, and particulate matter. Consequently, demand for our steam coal could be affected.

 

In addition, over the years, the Department of Justice, on behalf of the EPA, has filed lawsuits against a number of coal-fired electric generating facilities alleging violations of the new source review provisions of the CAA. The EPA has alleged that certain modifications have been made to these facilities without first obtaining certain permits issued under the new source review program. Several of these lawsuits have settled, but others remain pending. Depending on the ultimate resolution of these cases, demand for our coal could be affected.

 

Non-government organizations have also petitioned EPA to regulate coal mines as stationary sources under the Clean Air Act. On May 13, 2014, the D.C. Circuit in WildEarth Guardians v. United States Environmental Protection Agency upheld EPA’s denial of one such petition. On July 18, 2014, the D.C. Circuit denied a petition to rehear that case en banc. We cannot guarantee that these groups will not make similar efforts in the future. If such efforts are successful, emissions of these or other materials associated with our mining operations could become subject to further regulation pursuant to existing laws such as the CAA. In that event, we may be required to install additional emissions control equipment or take other steps to lower emissions associated with our operations, thereby reducing our revenues and adversely affecting our operations.

 

Climate Change

 

One by-product of burning coal is carbon dioxide or CO2, which EPA considers a GHG and a major source of concern with respect to climate change and global warming.

 

On the international level, the United States is one of almost 200 nations that agreed on December 12, 2015 to an international climate change agreement in Paris, France, that calls for countries to set their own GHG emission targets and be transparent about the measures each country will use to achieve its GHG emission targets; however, the agreement does not set binding GHG emission reduction targets. The Paris climate agreement entered into force in November 2016.

 

At the Federal level, EPA has taken a number of steps to regulate GHG emissions. For example, in August 2015, the EPA issued its final Clean Power Plan (the “CPP”) rules that establish carbon pollution standards for power plants, called CO2 emission performance rates. The EPA expects each state to develop implementation plans for power plants in its state to meet the individual state targets established in the CPP. The compliance period begins in 2022, and emission reductions will be phased in up to 2030. The EPA also proposed a federal compliance plan to implement the CPP in the event that an approvable state plan is not submitted to the EPA. Judicial challenges have been filed. On February 9, 2016, the U.S. Supreme Court granted a stay of the implementation of the CPP. By its terms, this stay will remain in effect throughout the pendency of the appeals process. The stay suspends the rule, including the requirement that states submit their initial plans by September 2016. The Supreme Court’s stay applies only to EPA’s regulations for CO2 emissions from existing power plants and will not affect EPA’s standards for new power plants. It is not yet clear how the courts will rule on the legality of the CPP. Additionally, it is unclear how the CPP will be impacted under President Trump’s new administration. If the rules were upheld at the conclusion of this appellate process and were implemented in their current form, demand for coal will likely be further decreased. The EPA also issued a final rule for new coal-fired power plants in August 2015, which essentially set performance standards for coal-fired power plants that requires partial carbon capture and sequestration (“CCS”). Additional legal challenges have been filed against the EPA’s rules for new power plants. The EPA’s GHG rules for new and existing power plants, taken together, have the potential to severely reduce demand for coal. In addition, passage of any comprehensive federal climate change and energy legislation could impact the demand for coal. Any reduction in the amount of coal consumed by North American electric power generators could reduce the price of coal that we mine and sell, thereby reducing our revenues and materially and adversely affecting our business and results of operations.

 

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Many states and regions have adopted greenhouse gas initiatives and certain governmental bodies have or are considering the imposition of fees or taxes based on the emission of greenhouse gases by certain facilities, including coal-fired electric generating facilities. For example, in 2005, ten northeastern states entered into the Regional Greenhouse Gas Initiative agreement (“RGGI”) calling for implementation of a cap and trade program aimed at reducing carbon dioxide emissions from power plants in the participating states. The members of RGGI have established in statute and/or regulation a carbon dioxide trading program. Auctions for carbon dioxide allowances under the program began in September 2008. Though New Jersey withdrew from RGGI in 2011, since its inception, several additional northeastern states and Canadian provinces have joined as participants or observers.

 

Following the RGGI model, five Western states launched the Western Regional Climate Action Initiative to identify, evaluate and implement collective and cooperative methods of reducing greenhouse gases in the region to 15% below 2005 levels by 2020. These states were joined by two additional states and four Canadian provinces and became collectively known as the Western Climate Initiative Partners. However, in November 2011, six states withdrew, leaving California and the four Canadian provinces as members. At a January 12, 2012 stakeholder meeting, this group confirmed a commitment and timetable to create the largest carbon market in North America and provide a model to guide future efforts to establish national approaches in both Canada and the U.S. to reduce GHG emissions. It is likely that these regional efforts will continue.

 

Many coal-fired plants have already closed or announced plans to close and proposed new construction projects have also come under additional scrutiny with respect to GHG emissions. There have been an increasing number of protests and challenges to the permitting of new coal-fired power plants by environmental organizations and state regulators due to concerns related to greenhouse gas emissions. Other state regulatory authorities have also rejected the construction of new coal-fueled power plants based on the uncertainty surrounding the potential costs associated with GHG emissions from these plants under future laws limiting the emissions of carbon dioxide. In addition, several permits issued to new coal-fired power plants without limits on GHG emissions have been appealed to the EPA’s Environmental Appeals Board. In addition, over 30 states have adopted mandatory “renewable portfolio standards,” which require electric utilities to obtain a certain percentage of their electric generation portfolio from renewable resources by a certain date. These standards range generally from 10% to 30%, over time periods that generally extend from the present until between 2020 and 2030. Other states may adopt similar requirements, and federal legislation is a possibility in this area. To the extent these requirements affect our current and prospective customers; they may reduce the demand for coal-fired power, and may affect long-term demand for our coal.

 

If mandatory restrictions on CO2 emissions are imposed, the ability to capture and store large volumes of carbon dioxide emissions from coal-fired power plants may be a key mitigation technology to achieve emissions reductions while meeting projected energy demands. A number of recent legislative and regulatory initiatives to encourage the development and use of carbon capture and storage technology have been proposed or enacted. For example, in October 2015, the EPA released a rule that established, for the first time, new source performance standards under the federal Clean Air Act for CO2 emissions from new fossil fuel-fired electric utility generating power plants. The EPA has designated partial carbon capture and sequestration as the best system of emission reduction for newly constructed fossil fuel-fired steam generating units at power plants to employ to meet the standard. However, widespread cost-effective deployment of CCS will occur only if the technology is commercially available at economically competitive prices and supportive national policy frameworks are in place.

 

There have also been attempts to encourage greater regulation of coalbed methane because methane has a greater GHG effect than CO2. Methane from coal mines can give rise to safety concerns, and may require that various measures be taken to mitigate those risks. If new laws or regulations were introduced to reduce coalbed methane emissions, those rules could adversely affect our costs of operations.

 

Finally, some scientists have warned that increasing concentrations of greenhouse gases (“GHGs”) in the Earth’s atmosphere may produce climate changes that have significant physical effects, such as increased frequency and severity of storms, droughts and floods and other climatic events. If these warnings are correct, and if any such effects were to occur in areas where we or our customers operate, they could have an adverse effect on our assets and operations.

 

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Clean Water Act

 

The Federal Clean Water Act (the “CWA”) and similar state and local laws and regulations affect coal mining operations by imposing restrictions on the discharge of pollutants, including dredged or fill material, into waters of the U.S. The CWA establishes in-stream water quality and treatment standards for wastewater discharges that are applied to wastewater dischargers through Section 402 National Pollutant Discharge Elimination System (“NPDES”) permits. Regular monitoring, as well as compliance with reporting requirements and performance standards, are preconditions for the issuance and renewal of Section 402 NPDES permits. Individual permits or general permits under Section 404 of the CWA are required to discharge dredged or fill materials into waters of the U.S. including wetlands, streams, and other areas meeting the regulatory definition. Expansion of EPA jurisdiction over these areas has the potential to adversely impact our operations. For example, the EPA released a final rule in May 2015 that attempted to clarify federal jurisdiction under the CWA over waters of the United States, but a number of legal challenges to this rule are pending, and implementation of the rule has been stayed nationwide. On January 13, 2017, the Supreme Court agreed to review the Sixth Circuit’s finding that it has jurisdiction to hear challenges to the rule. In February 2017, President Trump issued an executive order directing EPA and the Corps to review the WOTUS definition and to publish a proposed rule rescinding or revising the rule. At present, we cannot predict the outcome of the pending litigation or any revisions to the rule. To the extent the rule expands the scope of the CWA’s jurisdiction, we could face increased costs and delays with respect to obtaining permits for dredge and fill activities in wetland areas. Our surface coal mining and preparation plant operations typically require such permits to authorize activities such as the creation of slurry ponds, stream impoundments, and valley fills. The EPA, or a state that has been delegated such authority by the EPA, issues NPDES permits for the discharge of pollutants into navigable waters, while the U.S. Army Corps of Engineers (the “Corps”) issues dredge and fill permits under Section 404 of the CWA. Where Section 402 NPDES permitting authority has been delegated to a state, the EPA retains a limited oversight role. The CWA also gives the EPA an oversight role in the Section 404 permitting program, including drafting substantive rules governing permit issuance by the Corps, providing comments on proposed permits, and, in some cases, exercising the authority to delay or pre-empt Corps issuance of a Section 404 permit. The EPA has recently asserted these authorities more forcefully to question, delay, and prevent issuance of some Section 402 and 404 permits for surface coal mining in Appalachia. Currently, significant uncertainty exists regarding the obtaining of permits under the CWA for coal mining operations in Appalachia due to various initiatives launched by the EPA regarding these permits.

 

For instance, even though the Commonwealth of Kentucky and the State of West Virginia have been delegated the authority to issue NPDES permits for coal mines in those states, the EPA is taking a more active role in its review of NPDES permit applications for coal mining operations in Appalachia. The EPA issued final guidance on July 21, 2011 that encouraged EPA Regions 3, 4 and 5 to object to the issuance of state program NPDES permits where the Region does not believe that the proposed permit satisfies the requirements of the CWA and with regard to state issued general Section 404 permits, support the previously drafted Enhanced Coordination Process (“ECP”) among the EPA, the Corps, and the U.S. Department of the Interior for issuing Section 404 permits, whereby the EPA undertook a greater level of review of certain Section 404 permits than it had previously undertaken. The D.C. Circuit upheld EPA’s use of the ECP in July 2014. Future application of the ECP, such as may be enacted following notice and comment rulemaking, would have the potential to delay issuance of permits for surface coal mines, or to change the conditions or restrictions imposed in those permits.

 

The EPA also has statutory “veto” power under Section 404(c) to effectively revoke a previously issued Section 404 permit if the EPA determines, after notice and an opportunity for a public hearing, that the permit will have an “unacceptable adverse effect.” The Court have previously upheld the EPA’s ability to exercise this authority. Any future use of the EPA’s Section 404 “veto” power could create uncertainty with regard to our continued use of their current permits, as well as impose additional time and cost burdens on future operations, potentially adversely affecting our revenues.

 

The Corps is authorized to issue general “nationwide” permits for specific categories of activities that are similar in nature and that are determined to have minimal adverse environmental effects. We may no longer seek general permits under Nationwide Permit 21 (“NWP 21”) because in February 2012, the Corps reinstated the use of NWP 21, but limited application of NWP 21 authorizations to discharges with impacts not greater than a half-acre of water, including no more than 300 linear feet of streambed, and disallowed the use of NWP 21 for valley fills. This limitation remains in place in the new NWP 21 issued in January of 2017. If the newly issued NWP 21 cannot be used for any of our proposed surface coal mining projects, we will have to obtain individual permits from the Corps subject to the additional EPA measures discussed below with the uncertainties and delays attendant to that process.

 

We currently have a number of Section 404 permit applications pending with the Corps. Not all of these permit applications seek approval for valley fills or other obvious “fills”; some relate to other activities, such as mining through streams and the associated post-mining reconstruction efforts. We sought to prepare all pending permit applications consistent with the requirements of the Section 404 program. Our five year plan of mining operations does not rely on the issuance of these pending permit applications. However, the Section 404 permitting requirements are complex, and regulatory scrutiny of these applications, particularly in Appalachia, has increased such that our applications may not be granted or, alternatively, the Corps may require material changes to our proposed operations before it grants permits. While we will continue to pursue the issuance of these permits in the ordinary course of our operations, to the extent that the permitting process creates significant delay or limits our ability to pursue certain reserves beyond our current five year plan, our revenues may be negatively affected.

 

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Total Maximum Daily Load (“TMDL”) regulations under the CWA establish a process to calculate the maximum amount of a pollutant that an impaired water body can receive and still meet state water quality standards, and to allocate pollutant loads among the point- and non-point pollutant sources discharging into that water body. Likewise, when water quality in a receiving stream is better than required, states are required to conduct an anti-degradation review before approving discharge permits. The adoption of new TMDLs and load allocations or any changes to anti-degradation policies for streams near our coal mines could limit our ability to obtain NPDES permits, require more costly water treatment, and adversely affect our coal production.

 

Hazardous Substances and Wastes

 

The federal Comprehensive Environmental Response, Compensation and Liability Act (“CERCLA”), also known as the “Superfund” law, and analogous state laws, impose liability, without regard to fault or the legality of the original conduct, on certain classes of persons that are considered to have contributed to the release of a “hazardous substance” into the environment. These persons include the owner or operator of the site where the release occurred and companies that disposed or arranged for the disposal of the hazardous substances found at the site. Persons who are or were responsible for releases of hazardous substances under CERCLA may be subject to joint and several liabilities for the costs of cleaning up the hazardous substances that have been released into the environment and for damages to natural resources. Some products used by coal companies in operations generate waste containing hazardous substances. We are not aware of any material liability associated with the release or disposal of hazardous substances from our past or present mine sites.

 

The federal Resource Conservation and Recovery Act (“RCRA”) and corresponding state laws regulating hazardous waste affect coal mining operations by imposing requirements for the generation, transportation, treatment, storage, disposal and cleanup of hazardous wastes. Many mining wastes are excluded from the regulatory definition of hazardous wastes, and coal mining operations covered by SMCRA permits are by statute exempted from RCRA permitting. RCRA also allows the EPA to require corrective action at sites where there is a release of hazardous wastes. In addition, each state has its own laws regarding the proper management and disposal of waste material. While these laws impose ongoing compliance obligations, such costs are not believed to have a material impact on our operations.

 

In June 2010, EPA released a proposed rule to regulate the disposal of certain coal combustion by-products (“CCB”). The proposed rule sets forth two proposed avenues for the regulation of CCB under RCRA. The first option called for regulation of CCB under Subtitle C as a hazardous waste, which creates a comprehensive program of federally enforceable requirements for waste management and disposal. The second option called for regulation of CCB under Subtitle D as a solid waste, which gives EPA authority to set performance standards for solid waste management facilities and would be enforced primarily through state agencies and citizen suits. In December 2014, EPA finalized regulations that address the management of coal ash as a non-hazardous solid waste under Subtitle D. The rules impose engineering, structural and siting standards on surface impoundments and landfills that hold coal combustion wastes and mandate regular inspections. The rule also requires fugitive dust controls and imposes various monitoring, cleanup, and closure requirements. The rule leaves intact the Bevill exemption for beneficial uses of CCB, though it defers a final Bevill regulatory determination with respect to CCB that is disposed of in landfills or surface impoundments. Additionally, in December 2016, Congress passed the Water Infrastructure Improvements for the Nation Act, which provides for the establishment of state and EPA permit programs for the control of coal combustion residuals and authorizes states to incorporate EPA’s final rule for coal combustion residuals or develop other criteria that are at least as protective as the final rule. The costs of complying with these new requirements may result in a material adverse effect on our business, financial condition or results of operations, and could potentially increase our customers’ operating costs, thereby reducing their ability to purchase coal as a result. In addition, contamination caused by the past disposal of CCB, including coal ash, can lead to material liability to our customers under RCRA or other federal or state laws and potentially reduce the demand for coal.

 

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Endangered Species Act

 

The federal Endangered Species Act and counterpart state legislation protect species threatened with possible extinction. Protection of threatened and endangered species may have the effect of prohibiting or delaying us from obtaining mining permits and may include restrictions on timber harvesting, road building and other mining or agricultural activities in areas containing the affected species or their habitats. A number of species indigenous to our properties are protected under the Endangered Species Act. Based on the species that have been identified to date and the current application of applicable laws and regulations, however, we do not believe there are any species protected under the Endangered Species Act that would materially and adversely affect our ability to mine coal from our properties in accordance with current mining plans.

 

Use of Explosives

 

We use explosives in connection with our surface mining activities. The Federal Safe Explosives Act (“SEA”) applies to all users of explosives. Knowing or willful violations of the SEA may result in fines, imprisonment, or both. In addition, violations of SEA may result in revocation of user permits and seizure or forfeiture of explosive materials.

 

The storage of explosives is also subject to regulatory requirements. For example, pursuant to a rule issued by the Department of Homeland Security in 2007, facilities in possession of chemicals of interest (including ammonium nitrate at certain threshold levels) are required to complete a screening review in order to help determine whether there is a high level of security risk, such that a security vulnerability assessment and a site security plan will be required. It is possible that our use of explosives in connection with blasting operations may subject us to the Department of Homeland Security’s new chemical facility security regulatory program.

 

The costs of compliance with these requirements should not have a material adverse effect on our business, financial condition or results of operations.

 

In December 2014, OSM announced its decision to propose a rule that will address all blast generated fumes and toxic gases. OSM has not yet issued a proposed rule to address these blasts. We are unable to predict the impact, if any, of these actions by the OSM, although the actions potentially could result in additional delays and costs associated with our blasting operations.

 

Other Environmental and Mine Safety Laws

 

We are required to comply with numerous other federal, state and local environmental and mine safety laws and regulations in addition to those previously discussed. These additional laws include, for example, the Safe Drinking Water Act, the Toxic Substance Control Act and the Emergency Planning and Community Right-to-Know Act. The costs of compliance with these requirements is not expected to have a material adverse effect on our business, financial condition or results of operations.

 

Employees

 

To carry out our operations, our general partner and our subsidiaries employed 570 full-time employees as of December 31, 2016. None of the employees are subject to collective bargaining agreements. We believe that we have good relations with these employees and since our inception we have had no history of work stoppages or union organizing campaigns.

 

Available Information

 

Our internet address is http://www.rhinolp.com, and we make available free of charge on our website our Annual Reports on Form 10-K, our Quarterly Reports on Form 10-Q, our Current Reports on Form 8-K and Forms 3, 4 and 5 for our Section 16 filers (and amendments and exhibits, such as press releases, to such filings) as soon as reasonably practicable after we electronically file with or furnish such material to the SEC. Also included on our website are our “Code of Business Conduct and Ethics”, our “Insider Trading Policy,” “Whistleblower Policy” and our “Corporate Governance Guidelines” adopted by the board of directors of our general partner and the charters for the Audit Committee and Compensation Committee. Information on our website or any other website is not incorporated by reference into this report and does not constitute a part of this report.

 

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We file or furnish annual, quarterly and current reports and other documents with the SEC under the Securities Exchange Act of 1934 (the “Exchange Act”). The public may read and copy any materials that we file with the SEC at the SEC’s Public Reference Room at 100 F Street, N.E., Washington, D.C. 20549. The public may obtain information on the operation of the Public Reference Room by calling the SEC at 1-800-SEC-0330. Additionally, the SEC’s website, http://www.sec.gov, contains reports, proxy and information statements, and other information regarding issuers, including us, that file electronically with the SEC.

 

Item 1A. Risk Factors.

 

In addition to the factors discussed elsewhere in this report, including the financial statements and related notes, you should consider carefully the risks and uncertainties described below. If any of these risks or uncertainties, as well as other risks and uncertainties that are not currently known to us or that we currently believe are not material, were to occur, our business, financial condition or results of operation could be materially adversely affected and you may lose all or a significant part of your investment.

 

Risks Inherent in Our Business

 

Since the current maturity date of our credit facility is December 31, 2017, we are unable to demonstrate that we have sufficient liquidity to operate our business over the next twelve months and thus substantial doubt is raised about our ability to continue as a going concern. Accordingly, our independent registered public accounting firm has included an emphasis paragraph with respect to our ability to continue as a going concern in its report on our consolidated financial statements for the year ended December 31, 2016.

 

Since the current maturity date of our credit facility is December 31, 2017, we are unable to demonstrate that we have sufficient liquidity to operate our business over the next twelve months and thus substantial doubt is raised about our ability to continue as a going concern. Accordingly, our independent registered public accounting firm has included an emphasis paragraph with respect to our ability to continue as a going concern in its report on our consolidated financial statements for the year ended December 31, 2016. The presence of the going concern emphasis paragraph in our auditors’ report may have an adverse impact on our relationship with third parties with whom we do business, including our customers, vendors, lenders and employees, making it difficult to raise additional debt or equity financing to the extent needed and conduct normal operations. As a result, our business, results of operations, financial condition and prospects could be materially adversely affected.

 

On May 13, 2016, we entered into the Fifth Amendment of our amended and restated agreement that initially extended the term of the senior secured credit facility to July 31, 2017. Per the Fifth Amendment, the term of the credit facility automatically extended to December 31, 2017 when the revolving credit commitments were reduced to $55 million or less as of December 31, 2016. The Fifth Amendment also immediately reduced the revolving credit commitments under the credit facility to a maximum of $75 million and maintains the amount available for letters of credit at $30 million. As of December 31, 2016, we have met the requirements to extend the maturity date of the credit facility to December 31, 2017. In December 2016, we entered into the Seventh Amendment of our amended and restated credit agreement. The Seventh Amendment immediately reduces the revolving credit commitments by $11.0 million and provides for additional revolving credit commitment reductions of $2.0 million each on June 30, 2017 and September 30, 2017. The Seventh Amendment further reduces the revolving credit commitments over time on a dollar-for-dollar basis for the net cash proceeds received from any asset sales after the Seventh Amendment date once the aggregate net cash proceeds received exceeds $2.0 million. Since our credit facility has an expiration date of December 2017, we determined that our credit facility debt liability of $10.0 million at December 31, 2016 should be classified as a current liability on our consolidated statements of financial position. The classification of our credit facility balance as a current liability raises substantial doubt of our ability to continue as a going concern for the next twelve months. We are considering alternative financing options that could result in a new long-term credit facility. However, we may be unable to complete such a transaction on terms acceptable to us or at all.

 

There are other uncertainties as to our ability to access funding under our amended and restated credit agreement.  In order to borrow under our amended and restated credit facility, we must make certain representations and warranties to our lenders at the time of each borrowing.  If we are unable to make these representations and warranties, we would be unable to borrow under our amended and restated credit facility, absent a waiver.  Furthermore, if we violate any of the covenants or restrictions in our amended and restated credit agreement, including the maximum leverage ratio, some or all of our indebtedness may become immediately due and payable, and our lenders’ commitment to make further loans to us may terminate.  Although met coal prices and demand have improved in recent months, if weak demand and low prices for steam coal persist and if met coal prices and demand weaken, we may not be able to continue to give the required representations or meet all of the covenants and restrictions included in our credit facility. If we are unable to give a required representation or we violate a covenant or restriction, then we will need a waiver from our lenders in order to continue to borrow under our amended and restated credit agreement. There is no assurance that our lenders would agree to any such waiver.

 

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Our principal liquidity requirements are to finance current operations, fund capital expenditures and service our debt. Our principal sources of liquidity are cash generated by our operations and borrowings under our credit facility. If we are unable to extend the expiration date of our amended and restated credit facility or secure a replacement facility or borrow under our existing credit facility, we will lose a primary source of liquidity, and we may not be able to generate adequate cash flow from operations to fund our business, including amounts that may become due under our credit facility. Failure to obtain financing or to generate sufficient cash flow from operations could cause us to further curtail our operations and reduce our spending and to alter our business plan. We may also be required to consider other options, such as selling additional assets or merger opportunities, and depending on the urgency of our liquidity constraints, we may be required to pursue such an option at an inopportune time. If we are not able to fund our liquidity requirements for the next twelve months, we may not be able to continue as a going concern.

 

Our common units are currently traded on the OTCQB as a result of the NYSE’s delisting our common units and will trade indefinitely on the OTCQB or one of the other over-the-counter markets, which could adversely affect the market liquidity of our common units and harm our business.

 

Our common units were suspended from trading on the NYSE at the close of trading on December 17, 2015 and delisted from the NYSE on May 9, 2016. Our common units trade on the OTCQB under the ticker symbol “RHNO.” The common units will continue to trade on the OTCQB or one of the other over-the-counter markets.

 

Trading on the OTCQB or one of the other over-the-counter markets may result in a reduction in some or all of the following, each of which could have a material adverse effect on our unitholders:

 

  the liquidity of our common units;
     
  the market price of our common units;
     
  our ability to issue additional securities or obtain financing;
     
  the number of institutional and other investors that will consider investing in our common units;
     
  the number of market makers in our common units;
     
  the availability of information concerning the trading prices and volume of our common units; and
     
  the number of broker-dealers willing to execute trades in our common units.

 

Further, since our common units were delisted from the NYSE, we are no longer subject to the NYSE rules including rules requiring us to meet certain corporate governance standards. Without required compliance of these corporate governance standards, investor interest in our common units may decrease.

 

We may not have sufficient cash to enable us to pay the minimum quarterly distribution on our common units following establishment of cash reserves and payment of costs and expenses, including reimbursement of expenses to our general partner.

 

We may not have sufficient cash each quarter to pay the full amount of our minimum quarterly distribution of $4.45 per unit, or $17.80 per unit per year, which will require us to have available cash of approximately $63.2 million per quarter, or $252.8 million per year, based on the number of common and subordinated units outstanding as of December 31, 2016 and the general partner interest. 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 will fluctuate from quarter to quarter based on, among other things:

 

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  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 price at which we are able to sell coal, which is affected by the supply of and demand for domestic and foreign coal;
     
  the level of our operating costs, including reimbursement of expenses to our general partner and its affiliates. Our partnership agreement does not set a limit on the amount of expenses for which our general partner and its affiliates may be reimbursed;
     
  the proximity to and capacity of transportation facilities;
     
  the price and availability of alternative fuels;
     
  the impact of future environmental and climate change regulations, including those impacting coal-fired power plants;
     
  the level of worldwide energy and steel consumption;
     
  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;
     
  domestic and foreign governmental regulation, including changes in governmental regulation of the mining industry, the electric utility industry or the steel industry;
     
  changes in tax laws;
     
  weather conditions; and
     
  force majeure.

 

We may reduce or eliminate distributions at any time we determine that our cash reserves are insufficient or are otherwise required to fund current or anticipated future operations, capital expenditures, acquisitions, growth or expansion projects, debt repayment or other business needs. Beginning with the quarter ended September 30, 2014, distributions on our common units were below the minimum level and, beginning with the quarter ended June 30, 2015, we suspended the quarterly distribution on our common units altogether. Pursuant to our partnership agreement, our common units accrue arrearages every quarter when the distribution level is below the minimum quarterly distribution level and our subordinated units do not accrue such arrearages. In the future, if and as distributions are made for any quarter, the first priority is to pay the then minimum quarterly distribution to common unitholders. Any additional distribution amounts paid at that time are then paid to common unitholders until previously unpaid accumulated arrearage amounts have been paid in full. Thus, we have arrearages accumulating on our common units since the distribution level has been below our minimum quarterly level of $4.45 per unit. In addition, we have not paid any distributions on our subordinated units for any quarter after the quarter ended March 31, 2012. We may not have sufficient cash available for distributions on our common or subordinated units in the future. Any further reduction in the amount of cash available for distributions could impact our ability to pay any quarterly distribution on our common units. Moreover, we may not be able to increase distributions on our common units if we are unable to pay the accumulated arrearages on our common units as well as the full minimum quarterly distribution on our subordinated units.

 

A decline in coal prices could adversely affect our results of operations and cash available for distribution to our unitholders.

 

Our results of operations and the value of our coal reserves are significantly dependent upon the prices we receive for our coal as well as our ability to improve productivity and control costs. Prices for coal tend to be cyclical; however, prices have become more volatile and depressed as a result of oversupply in the marketplace. The prices we receive for coal depend upon factors beyond our control, including:

 

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  the supply of domestic and foreign coal;
     
  the demand for domestic and foreign coal, which is significantly affected by the level of consumption of steam coal by electric utilities and the level of consumption of metallurgical coal by steel producers;
     
  the price and availability of alternative fuels for electricity generation;
     
  the proximity to, and capacity of, transportation facilities;
     
  domestic and foreign governmental regulations, particularly those relating to the environment, climate change, health and safety;
     
  the level of domestic and foreign taxes;
     
  weather conditions;
     
  terrorist attacks and the global and domestic repercussions from terrorist activities; and
     
  prevailing economic conditions.

 

Any adverse change in these factors could result in weaker demand and lower prices for our products. In addition, the recent global economic downturn, coupled with the global financial and credit market disruptions, has had an impact on the coal industry generally and may continue to do so. The demand for electricity and steel may remain at low levels or further decline if economic conditions remain weak. If these trends continue, we may not be able to sell all of the coal we are capable of producing or sell our coal at prices comparable to recent years.

 

In addition to competing with other coal producers, we compete generally with producers of other fuels, such as natural gas. A decline in the price of natural gas has made natural gas more competitive against coal and resulted in utilities switching from coal to natural gas. Sustained low natural gas prices may also cause utilities to phase out or close existing coal-fired power plants or reduce or eliminate construction of any new coal-fired power plants, which could have a material adverse effect on demand and prices received for our coal. A substantial or extended decline in the prices we receive for our coal supply contracts could materially and adversely affect our results of operations.

 

We performed a comprehensive review of our current coal mining operation as well as potential future development projects for the year ended December 31, 2016 to ascertain any potential impairment losses. Based on the impairment analysis, we concluded that none of the coal properties, mine development costs or other coal mining equipment and related facilities were impaired at December 31, 2016. However, for the year ended December 31, 2016, we recorded $2.6 million of asset impairment losses and related charges associated with the 2015 sale of the Deane mining complex. Of the total $2.6 million non-cash impairment and other non-cash charges incurred, approximately $2.0 million related to impairment of the note receivable that was recorded in 2015 relating to the sale of the Deane mining complex. The additional $0.6 million impairment related to other non-recoverable items associated with the sale of the Deane mining complex. The $2.6 million asset impairment charge/loss for the Deane mining complex is recorded on the Asset impairment and related charges line of the consolidated statements of operations and comprehensive income.

 

We also performed a comprehensive review of our current coal mining operations as well as potential future development projects to ascertain any potential impairment losses during 2015. We identified various properties, projects and operations that were potentially impaired based upon changes in our strategic plans, market conditions or other factors, specifically in Northern Appalachia where market conditions related to our operations deteriorated in the fourth quarter of 2015. We believe that an oversupply of coal being produced in Northern Appalachia has contributed to depressed coal prices from this region. In addition to impairment charges related to certain Northern Appalachia operations, we also recorded asset impairment and related charges for the sale of the Deane mining complex and the Cana Woodford oil and natural gas investment that are discussed further below. We recorded approximately $31.1 million of total asset impairment and related charges related to property, plant and equipment for the year ended December 31, 2015, which is recorded on the Asset impairment and related charges line of the consolidated statements of operations and comprehensive income.

 

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We could be negatively impacted by the competitiveness of the global markets in which we compete and declines in the market demand for coal.

 

We compete with coal producers in various regions of the United States and overseas for domestic and international sales. The domestic demand for, and prices of, our coal primarily depend on coal consumption patterns of the domestic electric utility industry and the domestic steel industry. Consumption by the domestic electric utility industry is affected by the demand for electricity, environmental and other governmental regulations, technological developments and the price of competing coal and alternative fuel sources, such as natural gas, nuclear, hydroelectric and wind power and other renewable energy sources. Consumption by the domestic steel industry is primarily affected by economic growth and the demand for steel used in construction as well as appliances and automobiles. The competitive environment for coal is impacted by a number of the largest markets in the world, including the United States, China, Japan and India, where demand for both electricity and steel has supported prices for steam and metallurgical coal. The economic stability of these markets has a significant effect on the demand for coal and the level of competition in supplying these markets. The cost of ocean transportation and the value of the U.S. dollar in relation to foreign currencies significantly impact the relative attractiveness of our coal as we compete on price with foreign coal producing sources. During the last several years, the U.S. coal industry has experienced increased consolidation, which has contributed to the industry becoming more competitive. Increased competition by coal producers or producers of alternate fuels could decrease the demand for, or pricing of, or both, for our coal, adversely impacting our results of operations and cash available for distribution.

 

Portions of our coal reserves possess quality characteristics that enable us to mine, process and market them as either metallurgical coal or high quality steam coal, depending on prevailing market conditions.

 

Any change in consumption patterns by utilities away from the use of coal, such as resulting from current low natural gas prices, could affect our ability to sell the coal we produce, which could adversely affect our results of operations and cash available for distribution to our unitholders.

 

Steam coal accounted for approximately 90% of our coal sales volume for the year ended December 31, 2016. The majority of our sales of steam coal during this period were to electric utilities for use primarily as fuel for domestic electricity consumption. The amount of coal consumed by the domestic electric utility industry is affected primarily by the overall demand for electricity, environmental and other governmental regulations, and the price and availability of competing fuels for power plants such as nuclear, natural gas and oil as well as alternative sources of energy. We compete generally with producers of other fuels, such as natural gas and oil. A decline in price for these fuels could cause demand for coal to decrease and adversely affect the price of our coal. For example, sustained low natural gas prices have led, in some instances, to decreased coal consumption by electricity-generating utilities. If alternative energy sources, such as nuclear, hydroelectric, wind or solar, become more cost-competitive on an overall basis, demand for coal could decrease and the price of coal could be materially and adversely affected. Further, legislation requiring, subsidizing or providing tax benefit for the use of alternative energy sources and fuels, or legislation providing financing or incentives to encourage continuing technological advances in this area, could further enable alternative energy sources to become more competitive with coal. A decrease in coal consumption by the domestic electric utility industry could adversely affect the price of coal, which could materially adversely affect our results of operations and cash available for distribution to our unitholders.

 

Our mining operations are subject to extensive and costly environmental laws and regulations, and such current and future laws and regulations could materially increase our operating costs or limit our ability to produce and sell coal.

 

The coal mining industry is subject to numerous and extensive federal, state and local environmental laws and regulations, including laws and regulations pertaining to permitting and licensing requirements, air quality standards, plant and wildlife protection, reclamation and restoration of mining properties, the discharge of materials into the environment, the storage, treatment and disposal of wastes, protection of wetlands, surface subsidence from underground mining and the effects that mining has on groundwater quality and availability. The costs, liabilities and requirements associated with these laws and regulations are significant and time-consuming and may delay commencement or continuation of our operations. Moreover, the possibility exists that new laws or regulations (or new judicial interpretations or enforcement policies of existing laws and regulations) could materially affect our mining operations, results of operations and cash available for distribution to our unitholders, either through direct impacts such as those regulating our existing mining operations, or indirect impacts such as those that discourage or limit our customers’ use of coal. Violations of applicable laws and regulations would subject us to administrative, civil and criminal penalties and a range of other possible sanctions. The enforcement of laws and regulations governing the coal mining industry has increased substantially. As a result, the consequences for any noncompliance may become more significant in the future.

 

Our operations use petroleum products, coal processing chemicals and other materials that may be considered “hazardous materials” under applicable environmental laws and have the potential to generate other materials, all of which may affect runoff or drainage water. In the event of environmental contamination or a release of these materials, we could become subject to claims for toxic torts, natural resource damages and other damages and for the investigation and cleanup of soil, surface water, groundwater, and other media, as well as abandoned and closed mines located on property we operate. Such claims may arise out of conditions at sites that we currently own or operate, as well as at sites that we previously owned or operated, or may acquire.

 

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The government extensively regulates mining operations, especially with respect to mine safety and health, which imposes significant actual and potential costs on us, and future regulation could increase those costs or limit our ability to produce coal.

 

Coal mining is subject to inherent risks to safety and health. As a result, the coal mining industry is subject to stringent safety and health standards. Fatal mining accidents in the United States in recent years have received national attention and have led to responses at the state and federal levels that have resulted in increased regulatory scrutiny of coal mining operations, particularly underground mining operations. More stringent state and federal mine safety laws and regulations have included increased sanctions for non-compliance. Moreover, future workplace accidents are likely to result in more stringent enforcement and possibly the passage of new laws and regulations.

 

Within the last few years, the industry has seen enactment of the Federal Mine Improvement and New Emergency Response Act of 2006 (the “MINER Act”), subsequent additional legislation and regulation imposing significant new safety initiatives and the Dodd-Frank Act, which, among other things, imposes new mine safety information reporting requirements. The MINER Act significantly amended the Federal Mine Safety and Health Act of 1977 (the “Mine Act”), imposing more extensive and stringent compliance standards, increasing criminal penalties and establishing a maximum civil penalty for non-compliance, and expanding the scope of federal oversight, inspection, and enforcement activities. Following the passage of the MINER Act, the U.S. Mine Safety and Health Administration (“MSHA”) issued new or more stringent rules and policies on a variety of topics, including:

 

  sealing off abandoned areas of underground coal mines;
     
  mine safety equipment, training and emergency reporting requirements;
     
  substantially increased civil penalties for regulatory violations;
     
  training and availability of mine rescue teams;
     
  underground “refuge alternatives” capable of sustaining trapped miners in the event of an emergency;
     
  flame-resistant conveyor belt, fire prevention and detection, and use of air from the belt entry; and
     
  post-accident two-way communications and electronic tracking systems.

 

For example, in 2014, MSHA adopted a final rule that reduces the permissible concentration of respirable dust in underground coal mines from the current standard of 2.0 milligrams per cubic meter of air to 1.5 milligram per cubic meter. The rule had a phased implementation schedule, and the third and final phase of the rule became effective in August 2016. Under the phased approach, operators were required to adopt new measures and procedures for dust sampling, record keeping, and medical surveillance. Additionally, in September 2015, MSHA issued a proposed rule requiring the installation of proximity detection systems. Proximity detection is a technology that uses electronic sensors to detect motion and the distance between a miner and a machine. These systems provide audible and visual warnings, and automatically stop moving machines when miners are in the machines’ path. These and other new safety rules could result in increased compliance costs on our operations. Subsequent to passage of the MINER Act, various coal producing states, including West Virginia, Ohio and Kentucky, have enacted legislation addressing issues such as mine safety and accident reporting, increased civil and criminal penalties, and increased inspections and oversight. Other states may pass similar legislation in the future. Additional federal and state legislation that would further increase mine safety regulation, inspection and enforcement, particularly with respect to underground mining operations, has also been considered.

 

Although we are unable to quantify the full impact, implementing and complying with these new laws and regulations could have an adverse impact on our results of operations and cash available for distribution to our unitholders and could result in harsher sanctions in the event of any violations. Please read “Part 1, Item 1. Business—Regulation and Laws.”

 

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Penalties, fines or sanctions levied by MSHA could have a material adverse effect on our business, results of operations and cash available for distribution.

 

Surface and underground mines like ours and those of our competitors are continuously inspected by MSHA, which often leads to notices of violation. Recently, MSHA has been conducting more frequent and more comprehensive inspections. In addition, in July 2014, MSHA proposed a rule that revises its civil penalty assessment provisions and how regulators should approach calculating penalties, which, in some instances, could result in increased civil penalty assessments for medium and larger mine operators and contractors by 300% to 1,000%. MSHA issued a revised proposed rule in February 2015, but, to date, has not taken any further action. However, increased scrutiny by MSHA and enforcement against mining operations are likely to continue.

 

We have in the past, and may in the future, be subject to fines, penalties or sanctions resulting from alleged violations of MSHA regulations. Any of our mines could be subject to a temporary or extended shut down as a result of an alleged MSHA violation. Any future penalties, fines or sanctions could have a material adverse effect on our business, results of operations and cash available for distribution.

 

We may be unable to obtain and/or renew permits necessary for our operations, which could prevent us from mining certain reserves.

 

Numerous governmental permits and approvals are required for mining operations, and we can face delays, challenges to, and difficulties in acquiring, maintaining or renewing necessary permits and approvals, including environmental permits. The 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 may possibly preclude the continuance of ongoing mining operations or the development of future mining operations. For example, final guidance released by the CEQ regarding climate change considerations in the NEPA analyses may increase the likelihood of future challenges to the NEPA documents prepared for actions requiring federal approval. In addition, the public has certain statutory rights to comment upon and otherwise impact the permitting process, including through court intervention. Over the past few years, the length of time needed to bring a new surface mine into production has increased because of the increased time required to obtain necessary permits. The slowing pace at which permits are issued or renewed for new and existing mines has materially impacted production in Appalachia, but could also affect other regions in the future.

 

Section 402 National Pollutant Discharge Elimination System permits and Section 404 CWA permits are required to discharge wastewater and discharge dredged or fill material into waters of the United States. Expansion of EPA jurisdiction over these areas has the potential to adversely impact our operations. For example, the EPA released a final rule in May 2015 that attempted to clarify federal jurisdiction under the CWA over waters of the United States, but a number of legal challenges to this rule are pending, and implementation of the rule has been stayed nationwide. To the extent the rule expands the scope of the CWA’s jurisdiction, we could face increased costs and delays with respect to obtaining permits for dredge and fill activities in wetland areas. Our surface coal mining operations typically require such permits to authorize such activities as the creation of slurry ponds, stream impoundments, and valley fills. Although the CWA gives the EPA a limited oversight role in the Section 404 permitting program, the EPA has recently asserted its authorities more forcefully to question, delay, and prevent issuance of some Section 404 permits for surface coal mining in Appalachia. Currently, significant uncertainty exists regarding the obtaining of permits under the CWA for coal mining operations in Appalachia due to various initiatives launched by the EPA regarding these permits.

 

Our mining operations are subject to operating risks that could adversely affect production levels and operating costs.

 

Our mining operations are subject to conditions and events beyond our control that could disrupt operations, resulting in decreased production levels and increased costs.

 

These risks include:

 

  unfavorable geologic conditions, such as the thickness of the coal deposits and the amount of rock embedded in or overlying the coal deposit;
     
  inability to acquire or maintain necessary permits or mining or surface rights;
     
  changes in governmental regulation of the mining industry or the electric utility industry;
     
  adverse weather conditions and natural disasters;
     
  accidental mine water flooding;
     
  labor-related interruptions;
     
  transportation delays;
     
  mining and processing equipment unavailability and failures and unexpected maintenance problems; and
     
  accidents, including fire and explosions from methane.

 

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Any of these conditions may increase the cost of mining and delay or halt production at particular mines for varying lengths of time, which in turn could adversely affect our results of operations and cash available for distribution to our unitholders.

 

In general, mining accidents present a risk of various potential liabilities depending on the nature of the accident, the location, the proximity of employees or other persons to the accident scene and a range of other factors. Possible liabilities arising from a mining accident include workmen’s compensation claims or civil lawsuits for workplace injuries, claims for personal injury or property damage by people living or working nearby and fines and penalties including possible criminal enforcement against us and certain of our employees. In addition, a significant accident that results in a mine shut-down could give rise to liabilities for failure to meet the requirements of coal supply agreements especially if the counterparties dispute our invocation of the force majeure provisions of those agreements. We maintain insurance coverage to mitigate the risks of certain of these liabilities, including business interruption insurance, but those policies are subject to various exclusions and limitations and we cannot assure you that we will receive coverage under those policies for any personal injury, property damage or business interruption claims that may arise out of such an accident. Moreover, certain potential liabilities such as fines and penalties are not insurable risks. Thus, a serious mine accident may result in material liabilities that adversely affect our results of operations and cash available for distribution.

 

Fluctuations in transportation costs or disruptions in transportation services could increase competition or impair our ability to supply coal to our customers, which could adversely affect our results of operations and cash available for distribution to our unitholders.

 

Transportation costs represent a significant portion of the total cost of coal for our customers and, as a result, the cost of transportation is a critical factor in a customer’s purchasing decision. Increases in transportation costs could make coal a less competitive energy source or could make our coal production less competitive than coal produced from other sources.

 

Significant decreases in transportation costs could result in increased competition from coal producers in other regions. For instance, coordination of the many eastern U.S. coal loading facilities, the large number of small shipments, the steeper average grades of the terrain and a more unionized workforce are all issues that combine to make shipments originating in the eastern United States inherently more expensive on a per-mile basis than shipments originating in the western United States. Historically, high coal transportation rates from the western coal producing regions limited the use of western coal in certain eastern markets. The increased competition could have an adverse effect on our results of operations and cash available for distribution to our unitholders.

 

We depend primarily upon railroads, barges and trucks to deliver coal to our customers. Disruption of any of these services due to weather-related problems, strikes, lockouts, accidents, mechanical difficulties and other events could temporarily impair our ability to supply coal to our customers, which could adversely affect our results of operations and cash available for distribution to our unitholders.

 

In recent years, the states of Kentucky and West Virginia have increased enforcement of weight limits on coal trucks on their public roads. It is possible that other states may modify their laws to limit truck weight limits. Such legislation and enforcement efforts could result in shipment delays and increased costs. An increase in transportation costs could have an adverse effect on our ability to increase or to maintain production and could adversely affect our results of operations and cash available for distribution.

 

A shortage of skilled labor in the mining industry could reduce productivity and increase operating costs, which could adversely affect our results of operations and cash available for distribution to our unitholders.

 

Efficient coal mining using modern techniques and equipment requires skilled laborers. During periods of high demand for coal, the coal industry has experienced a shortage of skilled labor as well as rising labor and benefit costs, due in large part to demographic changes as existing miners retire at a faster rate than new miners are entering the workforce. If a shortage of experienced labor should occur or coal producers are unable to train enough skilled laborers, there could be an adverse impact on labor productivity, an increase in our costs and our ability to expand production may be limited. If coal prices decrease or our labor prices increase, our results of operations and cash available for distribution to our unitholders could be adversely affected.

 

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Unexpected increases in raw material costs, such as steel, diesel fuel and explosives could adversely affect our results of operations.

 

Our coal mining operations are affected by commodity prices. We use significant amounts of steel, diesel fuel, explosives and other raw materials in our mining operations, and volatility in the prices for these raw materials could have a material adverse effect on our operations. Steel prices and the prices of scrap steel, natural gas and coking coal consumed in the production of iron and steel fluctuate significantly and may change unexpectedly. Additionally, a limited number of suppliers exist for explosives, and any of these suppliers may divert their products to other industries. Shortages in raw materials used in the manufacturing of explosives, which, in some cases, do not have ready substitutes, or the cancellation of supply contracts under which these raw materials are obtained, could increase the prices and limit the ability of us or our contractors to obtain these supplies. Future volatility in the price of steel, diesel fuel, explosives or other raw materials will impact our operating expenses and could adversely affect our results of operations and cash available for distribution.

 

If we are not able to acquire replacement coal reserves that are economically recoverable, our results of operations and cash available for distribution to our unitholders could be adversely affected.

 

Our results of operations and cash available for distribution to our unitholders depend substantially on obtaining coal reserves that have geological characteristics that enable them to be mined at competitive costs and to meet the coal quality needed by our customers. Because we deplete our reserves as we mine coal, our future success and growth will depend, in part, upon our ability to acquire additional coal reserves that are economically recoverable. If we fail to acquire or develop additional reserves, our existing reserves will eventually be depleted. Replacement reserves may not be available when required or, if available, may not be capable of being mined at costs comparable to those characteristic of the depleting mines. We may not be able to accurately assess the geological characteristics of any reserves that we acquire, which may adversely affect our results of operations and cash available for distribution to our unitholders. Exhaustion of reserves at particular mines with certain valuable coal characteristics also may have an adverse effect on our operating results that is disproportionate to the percentage of overall production represented by such mines. Our ability to obtain other reserves in the future could be limited by restrictions under our existing or future debt agreements, competition from other coal companies for attractive properties, the lack of suitable acquisition candidates or the inability to acquire coal properties on commercially reasonable terms.

 

Inaccuracies in our estimates of coal reserves and non-reserve coal deposits could result in lower than expected revenues and higher than expected costs.

 

We base our coal reserve and non-reserve coal deposit estimates on engineering, economic and geological data assembled and analyzed by our staff, which is periodically audited by independent engineering firms. These estimates are also based on the expected cost of production and projected sale prices and assumptions concerning the permitability and advances in mining technology. The estimates of coal reserves and non-reserve coal deposits as to both quantity and quality are periodically updated to reflect the production of coal from the reserves, updated geologic models and mining recovery data, recently acquired coal reserves and estimated costs of production and sales prices. There are numerous factors and assumptions inherent in estimating quantities and qualities of coal reserves and non-reserve coal deposits and costs to mine recoverable reserves, including many factors beyond our control. Estimates of economically recoverable coal reserves necessarily depend upon a number of variable factors and assumptions, all of which may vary considerably from actual results. These factors and assumptions relate to:

 

  quality of coal;
     
  geological and mining conditions and/or effects from prior mining that may not be fully identified by available exploration data or which may differ from our experience in areas where we currently mine;
     
  the percentage of coal in the ground ultimately recoverable;
     
  the assumed effects of regulation, including the issuance of required permits, taxes, including severance and excise taxes and royalties, and other payments to governmental agencies;
     
  historical production from the area compared with production from other similar producing areas;
     
  the timing for the development of reserves; and
     
  assumptions concerning equipment and productivity, future coal prices, operating costs, capital expenditures and development and reclamation costs.

 

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For these reasons, estimates of the quantities and qualities of the economically recoverable coal attributable to any particular group of properties, classifications of coal reserves and non-reserve coal deposits based on risk of recovery, estimated cost of production and estimates of net cash flows expected from particular reserves as prepared by different engineers or by the same engineers at different times may vary materially due to changes in the above factors and assumptions. Actual production from identified coal reserve and non-reserve coal deposit areas or properties and revenues and expenditures associated with our mining operations may vary materially from estimates. Accordingly, these estimates may not reflect our actual coal reserves or non-reserve coal deposits. Any inaccuracy in our estimates related to our coal reserves and non-reserve coal deposits could result in lower than expected revenues and higher than expected costs, which could have a material adverse effect on our ability to make cash distributions.

 

We invest in non-coal natural resource assets, which could result in a material adverse effect on our results of operations and cash available for distribution to our unitholders.

 

Part of our business strategy is to expand our operations through strategic acquisitions, which includes investing in non-coal natural resources assets. Our executive officers do not have experience investing in or operating non-coal natural resources assets and we may be unable to hire additional management with relevant expertise in operating such assets. Acquisitions of non-coal natural resource assets could expose us to new and additional operating and regulatory risks, including commodity price risk, which could result in a material adverse effect on our results of operations and cash available for distribution to our unitholders.

 

The amount of estimated maintenance capital expenditures our general partner is required to deduct from operating surplus each quarter could increase in the future, resulting in a decrease in available cash from operating surplus that could be distributed to our unitholders.

 

Our partnership agreement requires our general partner to deduct from operating surplus each quarter estimated maintenance capital expenditures as opposed to actual maintenance capital expenditures in order to reduce disparities in operating surplus caused by fluctuating maintenance capital expenditures, such as reserve replacement costs or refurbishment or replacement of mine equipment. Our annual estimated maintenance capital expenditures for purposes of calculating operating surplus is based on our estimates of the amounts of expenditures we will be required to make in the future to maintain our long-term operating capacity. Our partnership agreement does not cap the amount of maintenance capital expenditures that our general partner may estimate. The amount of our estimated maintenance capital expenditures may be more than our actual maintenance capital expenditures, which will reduce the amount of available cash from operating surplus that we would otherwise have available for distribution to unitholders. The amount of estimated maintenance capital expenditures deducted from operating surplus is subject to review and change by the board of directors of our general partner at least once a year, with any change approved by the conflicts committee. In addition to estimated maintenance capital expenditures, reimbursement of expenses incurred by our general partner and its affiliates will reduce the amount of available cash from operating surplus that we would otherwise have available for distribution to our unitholders. Please read “—Risks Inherent in an Investment in Us—Cost reimbursements due to our general partner and its affiliates for services provided to us or on our behalf will reduce cash available for distribution to our unitholders. The amount and timing of such reimbursements will be determined by our general partner.”

 

Existing and future laws and regulations regulating the emission of sulfur dioxide and other compounds could affect coal consumers and as a result reduce the demand for our coal. A reduction in demand for our coal could adversely affect our results of operations and cash available for distribution to our unitholders.

 

Federal, state and local laws and regulations extensively regulate the amount of sulfur dioxide, particulate matter, nitrogen oxides, mercury and other compounds emitted into the air from electric power plants and other consumers of our coal. These laws and regulations can require significant emission control expenditures, and various new and proposed laws and regulations may require further emission reductions and associated emission control expenditures. A certain portion of our coal has a medium to high sulfur content, which results in increased sulfur dioxide emissions when combusted and therefore the use of our coal imposes certain additional costs on customers. Accordingly, these laws and regulations may affect demand and prices for our higher sulfur coal. Please read “Part I, Item 1. Business—Regulation and Laws.”

 

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Federal and state laws restricting the emissions of greenhouse gases could adversely affect our operations and demand for our coal.

 

One by-product of burning coal is CO2, which EPA considers a GHG, and a major source of concern with respect to climate change and global warming. Global warming has garnered significant public attention, and measures have been implemented or proposed at the international, federal, state and regional levels to limit GHG emissions. Please read “Part I, Item 1. Business—Regulation and Laws—Climate Change.”

 

For example, on the international level, the United States is one of almost 200 nations that agreed on December 12, 2015 to an international climate change agreement in Paris, France, that calls for countries to set their own GHG emission targets and be transparent about the measures each country will use to achieve its GHG emission targets; however, the agreement does not set binding GHG emission reduction targets. The Paris climate agreement entered into force in November 2016.

 

At the federal level, EPA has finalized a number of rules related to GHG emissions. For example, the EPA issued rules that establish carbon pollution standards for power plants, called CO2 emission performance rates. On February 9, 2016, the U.S. Supreme Court granted a stay of the implementation of the CPP. By its terms, this stay will remain in effect throughout the pendency of the appeals process. The stay suspends the rule, including the requirement that states submit their initial plans by September 2016. The Supreme Court’s stay applies only to EPA’s regulations for CO2 emissions from existing power plants and will not affect EPA’s standards for new power plants. It is not yet clear how the courts will rule on the legality of the CPP. The EPA also issued a final rule for new coal-fired power plants in August 2015, which essentially set performance standards for coal-fired power plants that requires partial carbon capture and sequestration. Additional legal challenges have been filed against the EPA’s rules for new power plants. The EPA’s GHG rules for new and existing power plants, taken together, have the potential to severely reduce demand for coal. In addition, passage of any comprehensive federal climate change and energy legislation could impact the demand for coal. Any reduction in the amount of coal consumed by North American electric power generators could reduce the price of coal that we mine and sell, thereby reducing our revenues and materially and adversely affecting our business and results of operations.

 

Many states and regions have adopted greenhouse gas initiatives and certain governmental bodies have or are considering the imposition of fees or taxes based on the emission of greenhouse gases by certain facilities, including coal-fired electric generating facilities. For example, in 2005, ten northeastern states entered into the Regional Greenhouse Gas Initiative agreement (the “RGGI”), calling for implementation of a cap and trade program aimed at reducing carbon dioxide emissions from power plants in the participating states. Following the RGGI model, several western states and Canadian provinces have confirmed a commitment and timetable to create a carbon market in North America. It is likely that these regional efforts will continue.

 

Many coal-fired plants have already closed or announced plans to close and proposed new construction projects have also come under additional scrutiny with respect to GHG emissions. There have been an increasing number of protests and challenges to the permitting of new coal-fired power plants by environmental organizations and state regulators due to concerns related to greenhouse gas emissions. Other state regulatory authorities have also rejected the construction of new coal-fueled power plants based on the uncertainty surrounding the potential costs associated with GHG emissions from these plants under future laws limiting the emissions of GHGs. In addition, several permits issued to new coal-fired power plants without limits on GHG emissions have been appealed to the EPA’s Environmental Appeals Board. In addition, over 30 states have adopted mandatory “renewable portfolio standards,” which require electric utilities to obtain a certain percentage of their electric generation portfolio from renewable resources by a certain date. These standards range generally from 10% to 30%, over time periods that generally extend from the present until between 2020 and 2030. Other states may adopt similar requirements, and federal legislation is a possibility in this area. To the extent these requirements affect our current and prospective customers; they may reduce the demand for coal-fired power, and may affect long-term demand for our coal.

 

If mandatory restrictions on carbon dioxide emissions are imposed, the ability to capture and store large volumes of carbon dioxide emissions from coal-fired power plants may be a key mitigation technology to achieve emissions reductions while meeting projected energy demands. A number of recent legislative and regulatory initiatives to encourage the development and use of CCS technology have been proposed or enacted. For example, in October 2015, the EPA released a rule that established, for the first time, new source performance standards under the federal Clean Air Act for CO2 emissions from new fossil fuel-fired electric utility generating power plants. The EPA has designated partial carbon capture and sequestration as the best system of emission reduction for newly constructed fossil fuel-fired steam generating units at power plants to employ to meet the standard. However, widespread cost-effective deployment of CCS will occur only if the technology is commercially available at economically competitive prices and supportive national policy frameworks are in place.

 

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In the meantime, 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” or “BACT.” As state permitting authorities continue to consider GHG control requirements as part of major source permitting BACT requirements, costs associated with new facility permitting and use of coal could increase substantially. A growing concern is the possibility that BACT will be determined to be the use of an alternative fuel to coal.

 

As a result of these current and proposed laws, regulations and trends, electricity generators may elect to switch to other fuels that generate less GHG emissions, possibly further reducing demand for our coal, which could adversely affect our results of operations and cash available for distribution to our unitholders.

 

Finally, some scientists have warned that increasing concentrations of GHGs in the Earth’s atmosphere may produce climate changes that have significant physical effects, such as increased frequency and severity of storms, droughts and floods and other climatic events. If these warnings are correct, and if any such effects were to occur in areas where we or our customers operate, they could have an adverse effect on our assets and operations.

 

Federal and state laws require bonds to secure our obligations to reclaim mined property. Our inability to acquire or failure to maintain, obtain or renew these surety bonds could have an adverse effect on our ability to produce coal, which could adversely affect our results of operations and cash available for distribution to our unitholders.

 

We are required under federal and state laws to place and maintain bonds to secure our obligations to repair and return property to its approximate original state after it has been mined (often referred to as “reclamation”) and to satisfy other miscellaneous obligations. Federal and state governments could increase bonding requirements in the future. In August 2016, the OSMRE issued a Policy Advisory discouraging state regulatory authorities from approving self-bonding arrangements. The Policy Advisory indicated that the OSMRE would begin more closely reviewing instances in which states accept self-bonds for mining operations. In the same month, the OSMRE also announced that it was beginning the rulemaking process to strengthen regulations on self-bonding. Certain business transactions, such as coal leases and other obligations, may also require bonding. We may have difficulty procuring or maintaining our surety bonds. Our bond issuers may demand higher fees, additional collateral, including supporting letters of credit or posting cash collateral or other terms less favorable to us upon those renewals. The failure to maintain or the inability to acquire sufficient surety bonds, as required by state and federal laws, could subject us to fines and penalties as well as the loss of our mining permits. Such failure could result from a variety of factors, including:

 

  the lack of availability, higher expense or unreasonable terms of new surety bonds;
     
  the ability of current and future surety bond issuers to increase required collateral; and
     
  the exercise by third-party surety bond holders of their right to refuse to renew the surety bonds.

 

We maintain surety bonds with third parties for reclamation expenses and other miscellaneous obligations. It is possible that we may in the future have difficulty maintaining our surety bonds for mine reclamation. Due to adverse economic conditions and the volatility of the financial markets, surety bond providers may be less willing to provide us with surety bonds or maintain existing surety bonds or may demand terms that are less favorable to us than the terms we currently receive. We may have greater difficulty satisfying the liquidity requirements under our existing surety bond contracts. As of December 31, 2016, we had $48.9 million in reclamation surety bonds, secured by $26.1 million in letters of credit outstanding under our credit agreement. Based on the Seventh Amendment, our credit agreement provides for a $49.1 million working capital revolving credit facility, of which up to $30.0 million may be used for letters of credit. If we do not maintain sufficient borrowing capacity under our revolving credit facility for additional letters of credit, we may be unable to obtain or renew surety bonds required for our mining operations. For more information, please read “Part II, Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations—Liquidity and Capital Resources—Credit Agreement.” If we do not maintain sufficient borrowing capacity or have other resources to satisfy our surety and bonding requirements, our operations and cash available for distribution to our unitholders could be adversely affected.

 

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We depend on a few customers for a significant portion of our revenues. If a substantial portion of our supply contracts terminate or if any of these customers were to significantly reduce their purchases of coal from us, and we are unable to successfully renegotiate or replace these contracts on comparable terms, then our results of operations and cash available for distribution to our unitholders could be adversely affected.

 

We sell a material portion of our coal under supply contracts. As of December 31, 2016, we had sales commitments for approximately 100% of our estimated coal production (including purchased coal to supplement our production) for the year ending December 31, 2017. When our current contracts with customers expire, our customers may decide not to extend or enter into new contracts. Of our total future committed tons, under the terms of the supply contracts, we will ship 84% in 2017, and 16% in 2018. We derived approximately 87.4% of our total coal revenues from coal sales to our ten largest customers for the year ended December 31, 2016, with affiliates of our top three customers accounting for approximately 48.5% of our coal revenues during that period.

 

In the absence of long-term contracts, our customers may decide to purchase fewer tons of coal than in the past or on different terms, including different pricing terms. Negotiations to extend existing contracts or enter into new long-term contracts with those and other customers may not be successful, and those customers may not continue to purchase coal from us under long-term coal supply contracts or may significantly reduce their purchases of coal from us. In addition, interruption in the purchases by or operations of our principal customers could significantly affect our results of operations and cash available for distribution. Unscheduled maintenance outages at our customers’ power plants and unseasonably moderate weather are examples of conditions that might cause our customers to reduce their purchases. Our mines may have difficulty identifying alternative purchasers of their coal if their existing customers suspend or terminate their purchases. For additional information relating to these contracts, please read “Part I, Item 1. Business—Customers—Coal Supply Contracts.”

 

Certain provisions in our long-term coal supply contracts may provide limited protection during adverse economic conditions, may result in economic penalties to us or permit the customer to terminate the contract.

 

Price adjustment, “price re-opener” and other similar provisions in our supply contracts may reduce the protection from short-term coal price volatility traditionally provided by such contracts. Price re-opener provisions typically require the parties to agree on a new price. Failure of the parties to agree on a price under a price re-opener provision can lead to termination of the contract. Any adjustment or renegotiations leading to a significantly lower contract price could adversely affect our results of operations and cash available for distribution to our unitholders.

 

Coal supply contracts also typically contain force majeure provisions allowing temporary suspension of performance by us or our customers during the duration of specified events beyond the control of the affected party. Most of our coal supply contracts also contain provisions requiring us to deliver coal meeting quality thresholds for certain characteristics such as Btu, sulfur content, ash content, hardness and ash fusion temperature. Failure to meet these specifications could result in economic penalties, including price adjustments, the rejection of deliveries or termination of the contracts. In addition, certain of our coal supply contracts permit the customer to terminate the agreement in the event of changes in regulations affecting our industry that increase the price of coal beyond a specified limit.

 

Defects in title in the coal properties that we own or loss of any leasehold interests could limit our ability to mine these properties or result in significant unanticipated costs.

 

We conduct a significant part of our mining operations on leased properties. A title defect or the loss of any lease could adversely affect our ability to mine the associated coal reserves. Title to most of our owned and leased properties and the associated mineral rights is not usually verified until we make a commitment to develop 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 grantors or lessors, as the case may be. Our right to mine some coal reserves would be adversely affected by defects in title or boundaries or if a lease expires. Any challenge to our title or leasehold interest could delay the exploration and development of the property and could ultimately result in the loss of some or all of our interest in the property. Mining operations from time to time may rely on a lease that we are unable to renew on terms at least as favorable, if at all. In such event, we may have to close down or significantly alter the sequence of mining operations or incur additional costs to obtain or renew such leases, which could adversely affect our future coal production. If we mine on property that we do not control, we could incur liability for such mining.

 

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Our work force could become unionized in the future, which could adversely affect our production and labor costs and increase the risk of work stoppages.

 

Currently, none of our employees are represented under collective bargaining agreements. However, all of our work force may not remain union-free in the future. If some or all of our work force were to become unionized, it could adversely affect our productivity and labor costs and increase the risk of work stoppages.

 

We depend on key personnel for the success of our business.

 

We depend on the services of our senior management team and other key personnel, including senior management of our general partner. The loss of the services of any member of senior management or key employee could have an adverse effect on our business and reduce our ability to make distributions to our unitholders. We may not be able to locate or employ on acceptable terms qualified replacements for senior management or other key employees if their services were no longer available.

 

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

 

The Federal Surface Mining Control and Reclamation Act of 1977 and counterpart state laws and regulations establish operational, reclamation and closure standards for all aspects of surface mining as well as most aspects of underground mining. Estimates of our total reclamation and mine closing liabilities are based upon permit requirements and our engineering expertise related to these requirements. The estimate of ultimate reclamation liability is reviewed both periodically by our management and annually by independent third-party engineers. The estimated liability can change significantly if actual costs vary from assumptions or if governmental regulations change significantly. Please read “Part II, Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations—Critical Accounting Policies and Estimates—Asset Retirement Obligations.”

 

Our debt levels may limit our flexibility in obtaining additional financing and in pursuing other business opportunities.

 

Our level of indebtedness could have important consequences to us, including the following:

 

  our ability to obtain additional financing, if necessary, for working capital, capital expenditures (including acquisitions) or other purposes may be impaired or such financing may not be available on favorable terms;
     
  covenants contained in our existing and future credit and debt arrangements will require us to meet financial tests that may affect our flexibility in planning for and reacting to changes in our business, including possible acquisition opportunities;
     
  we will need a portion of our cash flow to make principal and interest payments on our indebtedness, reducing the funds that would otherwise be available for operations, distributions to unitholders and future business opportunities;
     
  we may be more vulnerable to competitive pressures or a downturn in our business or the economy generally; and
     
  our flexibility in responding to changing business and economic conditions may be limited.

 

Increases in our total indebtedness would increase our total interest expense, which would in turn reduce our forecasted cash available for distribution. As of December 31, 2016 our current portion of long-term debt that will be funded from cash flows from operating activities during 2017 was approximately $10.0 million. Our ability to service our indebtedness will depend upon, among other things, our future financial and operating performance, which will be affected by prevailing economic conditions and financial, business, regulatory and other factors, some of which are beyond our control. If our operating results are not sufficient to service our current or future indebtedness, we will be forced to take actions such as reducing distributions, reducing or delaying our business activities, acquisitions, investments and/or capital expenditures, selling assets, restructuring or refinancing our indebtedness, or seeking additional equity capital or bankruptcy protection. We may not be able to affect any of these remedies on satisfactory terms, or at all.

 

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Our credit agreement contains operating and financial restrictions that may restrict our business and financing activities and limit our ability to pay distributions upon the occurrence of certain events.

 

The operating and financial restrictions and covenants in our credit agreement and any future financing agreements could restrict our ability to finance future operations or capital needs or to engage, expand or pursue our business activities. For example, our credit agreement restricts our ability to:

 

  incur additional indebtedness or guarantee other indebtedness;
     
  grant liens;
     
  make certain loans or investments;
     
  dispose of assets outside the ordinary course of business, including the issuance and sale of capital stock of our subsidiaries;
     
  change the line of business conducted by us or our subsidiaries;
     
  enter into a merger, consolidation or make acquisitions; or
     
  make distributions if an event of default occurs.

 

In addition, our payment of principal and interest on our debt will reduce cash available for distribution on our units. Our credit agreement limits our ability to pay distributions upon the occurrence of the following events, among others, which would apply to us and our subsidiaries:

 

  failure to pay principal, interest or any other amount when due;
     
  breach of the representations or warranties in the credit agreement;
     
  failure to comply with the covenants in the credit agreement;
     
  cross-default to other indebtedness;
     
  bankruptcy or insolvency;
     
  failure to have adequate resources to maintain, and obtain, operating permits as necessary to conduct our operations substantially as contemplated by the mining plans used in preparing the financial projections; and
     
  a change of control.

 

Any subsequent refinancing of our current debt or any new debt could have similar restrictions. Our ability to comply with the covenants and restrictions contained in our credit agreement may be affected by events beyond our control, including prevailing economic, financial and industry conditions. If market or other economic conditions deteriorate, our ability to comply with these covenants may be impaired. If we violate any of the restrictions, covenants, ratios or tests in our credit agreement, a significant portion of our indebtedness may become immediately due and payable, and our lenders’ commitment to make further loans to us may terminate. We might not have, or be able to obtain, sufficient funds to make these accelerated payments. In addition, our obligations under our credit agreement will be secured by substantially all of our assets, and if we are unable to repay our indebtedness under our credit agreement, the lenders could seek to foreclose on such assets. For more information, please read “Part II, Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations—Liquidity and Capital Resources—Credit Agreement.”

 

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Risks Inherent in an Investment in Us

 

Royal owns and controls our general partner. Our general partner has fiduciary duties to its owners, and the interests of its owners may differ significantly from, or conflict with, the interests of our public common unitholders.

 

Royal owns and controls our general partner. Please read “Part I, Item 1. Business—Recent Developments—Sale of our General Partner by Wexford.” Although our general partner has a fiduciary duty to manage us in a manner beneficial to us and our unitholders, the executive officers and directors of our general partner have a fiduciary duty to manage our general partner in a manner beneficial to its owners. Therefore, conflicts of interest may arise between its owners and our general partner, on the one hand, and 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 owners over the interests of our common unitholders. These conflicts include the following situations:

 

  our general partner is allowed to take into account the interests of parties other than us, such as its owners, in resolving conflicts of interest, which has the effect of limiting its fiduciary duty to our unitholders;
     
  neither our partnership agreement nor any other agreement requires Royal to pursue a business strategy that favors us;
     
  our partnership agreement limits the liability of and reduces fiduciary duties owed by our general partner and also restricts the remedies available to unitholders for actions that, without the limitations, might constitute breaches of fiduciary duty;
     
  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 capital expenditure and whether a capital expenditure is classified as a maintenance capital expenditure, which reduces operating surplus, or an expansion capital expenditure, which does not reduce operating surplus;
     
  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;
     
  our partnership agreement permits us to distribute up to $25.0 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 subordinated 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; 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, Royal, its owners and entities in which they have an interest may compete with us. Please read “—Our sponsor, Royal and affiliates of our general partner may compete with us.”

 

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Common units held by unitholders who are not eligible citizens will be subject to redemption.

 

In order to comply with U.S. laws with respect to the ownership of interests in mineral leases on federal lands, we have adopted certain requirements regarding those investors who own our common units. As used in this report, an eligible citizen means a person or entity qualified to hold an interest in mineral leases on federal lands. As of the date hereof, an eligible citizen must be: (1) a citizen of the United States; (2) a corporation organized under the laws of the United States or of any state thereof; or (3) an association of U.S. citizens, such as a partnership or limited liability company, organized under the laws of the United States or of any state thereof, but only if such association does not have any direct or indirect foreign ownership, other than foreign ownership of stock in a parent corporation organized under the laws of the United States or of any state thereof. For the avoidance of doubt, onshore mineral leases or any direct or indirect interest therein may be acquired and held by aliens only through stock ownership, holding or control in a corporation organized under the laws of the United States or of any state thereof. Unitholders who are not persons or entities who meet the requirements to be an eligible citizen run the risk of having their units redeemed by us at the lower of their purchase price cost or the then-current market price. The redemption price will be paid in cash or by delivery of a promissory note, as determined by our general partner.

 

Our general partner intends to limit its liability regarding our obligations.

 

Our general partner intends to limit its liability under contractual arrangements 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 fiduciary 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.

 

Our partnership agreement requires that we distribute all of our available cash, which could limit our ability to grow and make acquisitions.

 

We expect that we will distribute all of our available cash to our unitholders and will rely primarily upon external financing sources, including commercial bank borrowings and the issuance of debt and equity securities, to fund our acquisitions and expansion capital expenditures. As a result, to the extent we are unable to finance growth externally; our cash distribution policy will significantly impair our ability to grow.

 

In addition, because we distribute all 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 or our credit 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.

 

Our partnership agreement limits our general partner’s fiduciary duties to holders of our common and subordinated units.

 

Our partnership agreement contains provisions that modify and reduce the fiduciary standards to which our general partner would otherwise be held by state fiduciary duty law. 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:

 

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  how to allocate business opportunities among us and its affiliates;
     
  whether to exercise its limited 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 common and subordinated units for actions taken by our general partner that might otherwise constitute breaches of fiduciary duty.

 

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 required to make such determination, or take or decline to take such other action, in good faith, and will not be subject to any other or different standard imposed by our partnership agreement, Delaware law, or any other law, rule or regulation, or at equity;
     
  provides that our general partner will not have any liability to us or our unitholders for decisions made in its capacity as a general partner so long as it acted in good faith, meaning that it believed that the decision was in the best interest of our partnership;
     
  provides that our general partner and its officers and directors will not be liable for monetary damages 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 our general partner or its officers and directors, as the case may be, acted in bad faith or engaged in fraud or willful misconduct or, in the case of a criminal matter, acted with knowledge that the conduct was criminal; and
     
  provides that our general partner will not be in breach of its obligations under the partnership agreement or its fiduciary 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;
     
  (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;
     
  (3) on terms no less favorable to us than those generally being provided to or available from unrelated third parties; or
     
  (4) fair and reasonable to us, taking into account the totality of the relationships among the parties involved, including other transactions that may be particularly favorable or advantageous to us.

 

In connection with a situation involving a transaction with an affiliate or a conflict of interest, 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 and the board of directors of our general partner determines that the resolution or course of action taken with respect to the affiliate transaction or conflict of interest satisfies either of the standards set forth in subclauses (3) and (4) above, then it will be presumed that, in making its decision, 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.

 

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Our sponsor, Royal, and affiliates of our general partner may compete with us.

 

Our partnership agreement provides that our general partner will be restricted from engaging in any business activities other than acting as our general partner and those activities incidental to its ownership interest in us. However, affiliates of our general partner, including our sponsor, Royal, are not prohibited from engaging in other businesses or activities, including those that might be in direct competition with us. In addition, Royal and its affiliates may compete with us for investment opportunities and may own an interest in entities that compete with us. Further, Royal and its affiliates may acquire, develop or dispose of additional coal properties or other assets in the future without any obligation to offer us the opportunity to purchase or develop any of those assets.

 

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 and directors and Royal. Any such person or entity that becomes aware of a potential transaction, agreement, arrangement or other matter that may be an opportunity for us will not have any duty to communicate or offer such opportunity to us. Any such person or entity will not be liable to us or to any limited partner for breach of any fiduciary duty or other duty by reason of the fact that such person or entity pursues or acquires such opportunity for itself, directs such opportunity to another person or entity or does not communicate such opportunity or information to us. This may create actual and potential conflicts of interest between us and affiliates of our general partner and result in less than favorable treatment of us and our unitholders.

 

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 its incentive distribution rights, without the approval of the conflicts committee of its 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 has the right, at any time when there are no subordinated units outstanding and it has received incentive distributions at the highest level to which it is entitled (48.0%) for each of the prior four consecutive fiscal quarters, to reset the initial target distribution levels at higher levels based on our distributions at the time of the exercise of the reset election. Following a reset election by our general partner, the minimum quarterly distribution will be adjusted to equal the reset minimum quarterly distribution and the target distribution levels will be reset to correspondingly higher levels based on percentage increases above the reset minimum quarterly distribution.

 

If our general partner elects to reset the target distribution levels, it will be entitled to receive a number of common units and will retain its then-current general partner interest. The number of common units to be issued to our general partner will equal the number of common units, which would have entitled the holder to an average aggregate quarterly cash distribution in the prior two quarters equal to the average of the distributions to our general partner on the incentive distribution rights in the prior two quarters. We anticipate that our general partner would exercise this reset right in order to facilitate acquisitions or internal growth projects that would not be sufficiently accretive to cash distributions per common unit without such conversion. It is possible, however, that our general partner could exercise this reset election at a time when it is experiencing, or expects to experience, declines in the cash distributions it receives related to its incentive distribution rights and may, therefore, desire to be issued common units rather than retain the right to receive 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 our common unitholders would have otherwise received had we not issued new common units to our general partner in connection with resetting the target distribution levels.

 

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

 

Unlike the holders of common stock in a corporation, unitholders have only limited voting rights on matters affecting our business and, therefore, limited ability to influence management’s decisions regarding our business. Unitholders will 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 Royal, 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 will trade could be diminished because of the absence or reduction of a takeover premium in the trading price.

 

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Even if holders of our common units are dissatisfied, they cannot currently remove our general partner without its consent.

 

If our unitholders are dissatisfied with the performance of our general partner, they will have limited ability to remove our general partner. Unitholders are currently 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. The vote of the holders of at least 662/3% of all outstanding common and subordinated units voting together as a single class is required to remove our general partner. As of March 17, 2017, Royal owned an aggregate of approximately 55% of our common and subordinated units. Also, if our general partner is removed without cause during the subordination period and no units held by the holders of the subordinated units or their affiliates are voted in favor of that removal, all remaining subordinated units will automatically be converted into common units and any existing arrearages on the common units will be extinguished. Cause is narrowly defined in our partnership agreement to mean that a court of competent jurisdiction has entered a final, non-appealable judgment finding our general partner liable for actual fraud or willful or wanton misconduct in its capacity as our general partner. Cause does not include most cases of charges of poor management of the business.

 

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 in a merger or in a sale of all or substantially all of its assets without the consent of our unitholders. Furthermore, our partnership agreement does not restrict the ability of the members of our general partner to transfer their respective membership interests in our general partner to a third party. The new members of our general partner would then be in a position to replace the board of directors and executive officers of our general partner with their own 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.

 

Our general partner has a limited 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 will have the right, but not the obligation, which it may assign to any of its affiliates or to us, to acquire all, but not less than all, of the common units held by unaffiliated persons at a price 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 issuing 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 March 17, 2017, Royal owned an aggregate of approximately 52% of our common units and approximately 86% of our subordinated units.

 

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

 

Our partnership agreement does not limit the number of additional limited partner interests we may issue at any time without the approval of our unitholders. The issuance of additional common units, preferred units or other equity interests of equal or senior rank will have the following effects:

 

  our existing unitholders’ proportionate ownership interest in us will decrease;
  the amount of cash available for distribution on each unit may decrease;
  because a lower percentage of total outstanding units will be subordinated units, the risk that a shortfall in the payment of the minimum quarterly distribution will 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.

 

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The Series A preferred units are senior in right of distributions and liquidation and upon conversion, would result in the issuance of additional common units in the future, which could result in substantial dilution of our common unitholders’ ownership interests.

 

The Series A preferred units are a new class of partnership interests that rank senior to our common units with respect to distribution rights and rights upon liquidation. We are required to pay annual distributions on the Series A preferred units in an amount equal to the greater of (i) 50% of CAM Mining free cash flow (which is defined in our partnership agreement as (i) the total revenue of the our Central Appalachia business segment, minus (ii) the cost of operations (exclusive of depreciation, depletion and amortization) for the our Central Appalachia business segment, minus (iii) an amount equal to $6.50, multiplied by the aggregate number of met coal and steam coal tons sold by us from our Central Appalachia business segment) and (ii) an amount equal to the number of outstanding Series A preferred units multiplied by $0.80. If we fail to pay the any or all of the distributions in respect of the Series A preferred units, such deficiency will accrue until paid in full and we will not be permitted to pay any distributions on our partnership interests that rank junior to the Series A preferred units, including our common units. The preferred units also rank senior to the common units in right of liquidation, and will be entitled to receive a liquidation preference in any such case.

 

We may convert the Series A preferred units into common units at any time on or after the time at which the amount of aggregate distributions paid in respect of each Series A preferred unit exceeds $10.00 per unit. All unconverted Series A preferred units will convert into common units on December 31, 2021. The number of common units issued in any conversion will be based on the volume-weighted average closing price of the common units for 90 days preceding the date of conversion. Accordingly, the lower the trading price of our common units over the 90 day measurement period, the greater the number of common units that will be issued upon conversion of the preferred units, which would result in greater dilution to our existing common unitholders. Dilution has the following effects on our common unitholders:

 

  an existing unitholder’s proportionate ownership interest in us will decrease;
     
  the amount of cash available for distribution on each unit may decrease;
     
  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 the preferred units are converted into more than 66 2/3% of our common units, the holders of the preferred will have the right to remove our general partner.

 

Holders of our Series A preferred units have substantial negative control rights.

 

For as long as the Series A preferred units are outstanding, we will be restricted from taking certain actions without the consent of the holders of a majority of the Series A preferred units, including: (i) the issuance of additional Series A preferred units, or securities that rank senior or equal to the Series A preferred units; (ii) the sale or transfer of CAM Mining, LLC or a material portion of its assets; (iii) the repurchase of common units, or the issuance of rights or warrants to holders of common units entitling them to purchase common units at less than fair market value; (iv) consummation of a spin off; (v) the incurrence, assumption or guaranty indebtedness for borrowed money in excess of $50.0 million except indebtedness relating to entities or assets that are acquired by the Partnership or its affiliates that is in existence at the time of such acquisition or (vi) the modification of CAM Mining’s accounting principles or the financial or operational reporting principles of the our Central Appalachia business segment, subject to certain exceptions. These consent rights effectively add a constituency to our fundamental decision-making process, and failure to obtain such consent from the Series A preferred holders could prevent us from taking an action that our management or board of directors otherwise view as prudent or necessary for our business operations or the execution of our business strategy.

 

The market price of our common units could be adversely affected by sales of substantial amounts of our common units in the public or private markets, including sales by Royal or other large holders.

 

As of March 17, 2017, we had 12,905,799 common units, 1,235,534 subordinated units and 1,500,000 Series A preferred units outstanding. All of the subordinated units will convert into common units on a one-for-one basis at the end of the subordination period. On March 21, 2016, we issued 6,000,000 common units to Royal in a private placement. In connection with this issuance, we entered into a registration rights agreement with Royal which grants Royal piggyback registration rights under certain circumstances with respect to these common units. In addition, under our partnership agreement, our general partner and its affiliates (including Royal) have registration rights relating to the offer and sale of any units that they hold, subject to certain limitations. Sales by Royal or other large holders of a substantial number of our common units in the public markets, or the perception that such sales might occur, could have a material adverse effect on the price of our common units or could impair our ability to obtain capital through an offering of equity securities.

 

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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 will reduce cash available for distribution to our unitholders. The amount and timing of such reimbursements will be determined by our general partner.

 

Prior to making any distribution on the common units, we will reimburse our general partner and its affiliates for all expenses they incur and payments they make on our behalf. Our partnership agreement does not set a limit on the amount of expenses for which our general partner and its affiliates may be reimbursed. These expenses include salary, bonus, incentive compensation and other amounts paid to persons who perform services for us or on our behalf and expenses allocated to our general partner by its affiliates. Our partnership agreement provides that our general partner will determine in good faith the expenses that are allocable to us. The reimbursement of expenses and payment of fees, if any, to our general partner and its affiliates will reduce the amount of available cash to pay cash distributions to our unitholders.

 

While our partnership agreement requires us to distribute all of our available cash, our partnership agreement, including provisions requiring us to make cash distributions contained therein, may be amended.

 

While our partnership agreement requires us to distribute all of our available cash, our partnership agreement, including provisions requiring us to make cash distributions contained therein, may be amended. Our partnership agreement generally may not be amended during the subordination period without the approval of our public common unitholders. However, our partnership agreement can be amended with the consent of our general partner and the approval of a majority of the outstanding common units (including common units held by Royal) after the subordination period has ended. As of March 17, 2017, Royal owned approximately 51.1% of the outstanding common units and 85.9% of our outstanding subordinated units.

 

Unitholders may have liability to repay distributions and in certain circumstances may be personally liable for our obligations.

 

Under certain circumstances, unitholders may have to repay amounts wrongfully returned or distributed to them. Under Section 17-607 of the Delaware Revised Uniform Limited Partnership Act (the “Delaware Act”), we may not make a distribution to our unitholders if the distribution would cause our liabilities to exceed the fair value of our assets. Delaware law provides that for a period of three years from the date of the impermissible distribution, limited partners who received the distribution and who knew at the time of the distribution that it violated Delaware law will be liable to the limited partnership for the distribution amount. A purchaser of units who becomes a limited partner is liable for the obligations of the transferring limited partner to make contributions to the partnership that are known to the purchaser of units at the time it became a limited partner and for unknown obligations if the liabilities could be determined from the partnership agreement. Liabilities to partners on account of their partnership interests and liabilities that are non-recourse to the partnership are not counted for purposes of determining whether a distribution is permitted.

 

It may be determined that the right, or the exercise of the right by the limited partners as a group, to (i) remove or replace our general partner, (ii) approve some amendments to our partnership agreement or (iii) take other action under our partnership agreement constitutes “participation in the control” of our business. A limited partner that participates in the control of our business within the meaning of the Delaware Act may be held personally liable for our obligations under the laws of Delaware, to the same extent as our general partner. This liability would extend to persons who transact business with us under the reasonable belief that the limited partner is a general partner. Neither our partnership agreement nor the Delaware Act specifically provides for legal recourse against our general partner if a limited partner were to lose limited liability through any fault of our general partner.

 

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Tax Risks

 

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 our partnership status for U.S. federal income tax purposes changes or we become subject to material additional amounts of entity-level taxation for state tax purposes, then the value of our common units may be substantially reduced.

 

We are currently treated as a partnership for U.S. federal income tax purposes. A publicly traded partnership such as us is treated as a partnership only if it satisfies a “qualifying income” requirement. Based on our current operations we believe that we satisfy the qualifying income requirement and will be treated as a partnership. We may, however, decide that it is in our best interest to be treated as a corporation for U.S. federal income tax purposes. A failure to meet the qualifying income requirement, a change in current law, or a decision to elect corporate treatment, 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 U.S. federal income tax purposes, we would pay federal income tax on our taxable income at the corporate tax rate and would likely pay state and local income tax at varying rates. Any 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 treatment as a corporation may result in 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 additional amounts of entity level taxation for federal or state tax purposes, the minimum quarterly distribution amount and the target distribution amounts may be adjusted to reflect the impact of that law on us. Changes in current state law may subject us to additional entity level taxation by individual states. Because of widespread state budget deficits and other reasons, several states are evaluating ways to subject partnerships to entity level taxation through the imposition of state income, franchise and other forms of taxation. Imposition of any such taxes may substantially reduce the value of our common units.

 

Although we monitor our level of non-qualifying income closely and attempt to manage our operations to ensure compliance with the qualifying income requirement, given the continued weak demand and low prices for met and steam coal, there is a risk that we will not be able to continue to meet the qualifying income level necessary to maintain our status as a partnership for federal income tax purposes.

 

As a publicly traded partnership, we may be treated as a corporation for federal income tax purposes unless 90% or more of our gross income in each year consists of certain identified types of “qualifying income.” In addition to qualifying income, like many other publicly traded partnerships, we also generate ancillary income that may not constitute qualifying income. Although we monitor our level of gross income that may not constitute qualifying income closely and attempt to manage our operations to ensure compliance with the qualifying income requirement, given the continued weak demand and low prices for met and steam coal, the sale of which generates qualifying income, there is a risk that we will not be able to continue to meet the qualifying income level necessary to maintain our status as a publicly-traded partnership. To the extent we become aware that we may not generate or have not generated sufficient qualifying income with respect to a period, we can and would take action to preserve our treatment as a partnership for federal income tax purposes, including seeking relief from the IRS. Section 7704(e) of the Internal Revenue Code provides for the possibility of relief upon, among other things, determination by the IRS that such failure to meet the qualifying income requirement was inadvertent. However, we are unaware of examples of such relief being sought by a publicly traded partnership.

 

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 U.S. 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, from time to time, members of Congress propose and consider such substantive changes to the existing federal income tax laws that affect publicly traded partnerships. Although there is not current legislative proposal, a prior legislative proposal would have eliminated 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.

 

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In addition on January 24, 2017, final regulations regarding which activities give rise to qualifying income within the meaning of Section 7704 of the Code (the “Final Regulations”) were published in the Federal Register. We do not believe the Final Regulations affect our ability to be treated as a partnership for U.S. federal income tax purposes.

 

Any modifications to the U.S. federal income tax laws may be applied retroactively and could make it more difficult or impossible to meet the exception for certain publicly traded partnerships to be treated as partnerships for U.S. 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.

 

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 substantially reduce the value of our common units.

 

We have not requested a ruling from the IRS with respect to our treatment as a partnership for U.S. federal income tax purposes or any other matter affecting us. The IRS may adopt positions that differ from the positions we take. A court may not agree with some or all of the positions we take. Any contest with the IRS may materially and adversely impact the market for our common units and the price at which they trade. Our costs of any contest with the IRS will be borne indirectly by our unitholders and our general partner because the costs may substantially reduce the value of our common units. We have requested and obtained a favorable private letter ruling from the IRS to the effect that, based on facts presented in the private letter ruling request, income from management fees, cost reimbursements and cost-sharing payments related to our management and operation of mining, production, processing, and sale of coal and from energy infrastructure support services will constitute “qualifying income” within the meaning of Section 7704 of the Code.

 

If the IRS makes audit adjustments to our income tax returns for tax years beginning after December 31, 2017, it (and some states) may assess and collect any taxes (including any applicable penalties and interest) resulting from such audit adjustment directly from us, in which case our cash available for distribution to our unitholders might be substantially reduced.

 

Pursuant to the Bipartisan Budget Act of 2015, for tax years beginning after December 31, 2017, if the IRS makes audit adjustments to our income tax returns, it (and some states) may assess and collect any taxes (including any applicable penalties and interest) resulting from such audit adjustment directly from us. To the extent possible under the new rules, our general partner may elect to either pay the taxes (including any applicable penalties and interest) directly to the IRS or, if we are eligible, issue a revised Schedule K-1 to each unitholder with respect to an audited and adjusted return. Although our general partner may elect to have our unitholders take such audit adjustment into account in accordance with their interests in us during the tax year under audit, there can be no assurance that such election will be practical, permissible or effective in all circumstances. As a result, our current unitholders may bear some or all of the tax liability resulting from such audit adjustment, even if such unitholders did not own units in us during the tax year under audit. If, as a result of any such audit adjustment, we are required to make payments of taxes, penalties and interest, our cash available for distribution to our unitholders might be substantially reduced. These rules are not applicable for tax years beginning on or prior to December 31, 2017.

 

Our unitholders are required to pay taxes on their share of our income even if they do not receive any cash distributions from us.

 

Our unitholders are required to pay federal income taxes and, in some cases, state and local income taxes, on their share of our taxable income, whether or not they receive cash distributions from us. Our unitholders may not receive cash distributions from us equal to their share of our taxable income or even equal to the actual tax due with respect to that income.

 

We anticipate engaging in transactions to reduce our indebtedness and manage our liquidity that generate taxable income (including cancellation of indebtedness income) allocable to unitholders, and income tax liabilities arising therefrom may exceed the value of your investment in us.

 

In response to current market conditions, from time to time we may consider engaging in transactions to delever us and manage our liquidity that would result in income and gain to our unitholders without a corresponding cash distribution. For example, we may sell assets and use the proceeds to repay existing debt or fund capital expenditures, in which case, you would be allocated taxable income and gain resulting from the sale without receiving a cash distribution. Further, we may pursue opportunities to reduce our existing debt, such as debt exchanges, debt repurchases, or modifications and extinguishment of our existing debt that would result in “cancellation of indebtedness income” (also referred to as “COD income”) being allocated to our unitholders as ordinary taxable income. Unitholders may be allocated COD income, and income tax liabilities arising therefrom may exceed the current value of your investment in us.

 

Entities taxed as corporations may have net operating losses to offset COD income or may otherwise qualify for an exception to the recognition of COD income, such as the bankruptcy or insolvency exceptions. As long as we are treated as a partnership, however, these exceptions are not available to the partnership and are only available to a unitholder if the unitholder itself is insolvent or in bankruptcy. As a result, these exceptions generally would not apply to prevent the taxation of COD income allocated to our unitholders. The ultimate tax effect of any such income allocations will depend on the unitholder’s individual tax position, including, for example, the availability of any suspended passive losses that may offset some portion of the allocable COD income. Unitholders may, however, be allocated substantial amounts of ordinary income subject to taxation, without any ability to offset such allocated income against any capital losses attributable to the unitholder’s ultimate disposition of its units. Unitholders are encouraged to consult their tax advisors with respect to the consequences to them of COD income.

 

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

 

If you sell your units, you will recognize gain or loss equal to the difference between the amount realized and your tax basis in those units. Because distributions in excess of your allocable share of our net taxable income decrease your tax basis in your 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 therein, even if the price you receive is less than your original cost. In addition, because the amount realized includes a unitholder’s share of our non-recourse liabilities, if you sell your units, you may incur a tax liability in excess of the amount of cash you receive from the sale.

 

A substantial portion of the amount realized from the sale of your units, whether or not representing gain, may be taxed as ordinary income to you due to potential recapture items, including depreciation recapture. Thus, you may recognize both ordinary income and capital loss from the sale of your units if the amount realized on a sale of your units is less than your adjusted basis in the units.

 

Net capital loss may only offset capital gains and, in the case of individuals, up to $3,000 of ordinary income per year. In the taxable period in which you sell your units, you may recognize ordinary income from our allocations of income and gain to you prior to the sale and from recapture items that generally cannot be offset by any capital loss recognized upon the sale of units.

 

Tax-exempt entities and non-U.S. persons face unique tax issues from owning our 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 (known as 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 subject to withholding taxes imposed at the highest effective tax rate applicable to such non-U.S. persons, and each non-U.S. person will be required to file U.S. federal tax returns and pay tax on its share 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.

 

We treat each purchaser of common units as having the same tax benefits without regard to the common units actually 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 have adopted depreciation and amortization positions that may not conform to all aspects of existing Treasury Regulations. A successful IRS challenge to those positions could adversely affect the amount of tax benefits available to 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 our items of income, gain, loss and deduction between transferors and transferees of our common units each month based upon the ownership of our units on the first day of each month (the “Allocation Date”), instead of on the basis of the date a particular common unit is transferred. Similarly, we generally allocate gain or loss realized on the sale or other disposition of our assets or, in the discretion of the general partner, any other extraordinary item of income, gain, loss or deduction on the Allocation Date. Nonetheless, we allocate certain deductions for depreciation of capital additions based upon the date the underlying property is placed in service. The U.S. Department of the Treasury adopted final Treasury Regulations allowing a similar monthly simplifying convention, but such regulations do not specifically authorize all aspects of our proration method. If the IRS were to challenge our proration method or new Treasury Regulations were issued, we may be required to change our allocation of items of income, gain, loss and deduction among our unitholders.

 

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A unitholder whose units are the subject of a securities loan (e.g., a loan to a “short seller” to cover a short sale of units) may be considered to have disposed of those units. If so, the unitholder would no longer be treated for tax purposes as a partner with respect to those units during the period of the loan and could 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 units are the subject of a securities loan may be considered to have disposed of the loaned units. In that case, the unitholder may no longer be treated for tax purposes as a partner in us with respect to those units during the period of the loan 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 units may not be reportable by the unitholder and any cash distributions received by the unitholder as to those 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 should consult a tax advisor to discuss whether it is advisable to modify any applicable brokerage account agreements to prohibit their brokers from borrowing their units.

 

We have adopted certain valuation methodologies in determining a unitholder’s allocations of income, gain, loss and deduction. The IRS may challenge these methodologies or the resulting allocations, which 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 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 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 timing or amount of taxable income or loss being allocated to our unitholders. It also could affect the amount of gain from our unitholders’ sale of common units and could have a negative impact on the value of the common units or result in audit adjustments to our unitholders’ tax returns without the benefit of additional deductions.

 

The sale or exchange of 50% or more of our capital and profits interests during any twelve-month period will result in the termination of our partnership for federal income tax purposes.

 

We will be considered to have constructively terminated for U.S. 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. As of January 13, 2017, Royal Energy Resources, Inc. owned 44.4% of the total interests in our capital and profits. Therefore, a transfer by Royal Energy Resources, Inc. of all or a portion of its interests in us could, in conjunction with the trading of common units held by the public, result in a termination of our partnership for federal income tax purposes. For purposes of determining whether the 50% threshold has been met, multiple sales of the same unit will be counted only once. Our termination would, among other things, result in the closing of our taxable year for all unitholders, which would result in us filing two tax returns (and our unitholders could receive two Schedules K-1) for one calendar year and could result in a deferral of depreciation deductions allowable in computing our taxable income. In the case of a unitholder reporting on a taxable year other than a 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 the unitholder’s 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, we would be treated as a new partnership for tax purposes. If treated as a new partnership, we must make new tax elections and could be subject to penalties if we are unable to determine that a technical termination occurred. The IRS has announced a relief procedure whereby if a publicly traded partnership that has technically terminated requests and the IRS grants special relief, among other things, the partnership may be permitted to provide only a single Schedule K-1 to unitholders for the tax years in which the termination occurs.

 

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.

 

The Fiscal Year 2016 Budget proposed by the President recommends elimination of certain key U.S. federal income tax preferences relating to coal exploration and development (the “Budget Proposal”). The Budget Proposal would (1) eliminate current deductions and 60-month amortization for exploration and development costs relating to coal and other hard mineral fossil fuels, (2) repeal the percentage depletion allowance with respect to coal properties, (3) repeal capital gains treatment of coal and lignite royalties, and (4) exclude from the definition of domestic production gross receipts all gross receipts derived from the sale, exchange, or other disposition of coal, other hard mineral fossil fuels, or primary products thereof. 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 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.

 

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

 

In addition to U.S. federal income taxes, unitholders will likely be subject to other taxes, including 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 they do not live in any of those jurisdictions. Unitholders will likely be required to file state and local income tax returns and pay state and local income taxes in some or all of these various jurisdictions. Further, unitholders may be subject to penalties for failure to comply with those requirements. We conduct business in a number of states, most of which also impose an income tax on corporations and other entities. In addition, many of these states also impose a personal income tax on individuals. As we make acquisitions or expand our business, we may own assets or conduct business in additional states that impose a personal income tax. It is your responsibility to file all U.S. federal, state and local tax returns.

 

Item 1B. Unresolved Staff Comments

 

None.

 

Item 2. Properties.

 

See “Part I, Item 1. Business” for information about our coal operations and other natural resource assets.

 

Coal Reserves and Non-Reserve Coal Deposits

 

We base our coal reserve and non-reserve coal deposit estimates on engineering, economic and geological data assembled and analyzed by our staff. These estimates are also based on the expected cost of production and projected sale prices and assumptions concerning the permitability and advances in mining technology. The estimates of coal reserves and non-reserve coal deposits as to both quantity and quality are periodically updated to reflect the production of coal from the reserves, updated geologic models and mining recovery data, coal reserves recently acquired and estimated costs of production and sales prices. Changes in mining methods may increase or decrease the recovery basis for a coal seam as will plant processing efficiency tests. We maintain reserve and non-reserve coal deposit information in secure computerized databases, as well as in hard copy. The ability to update and/or modify the estimates of our coal reserves and non-reserve coal deposits is restricted to a few individuals and the modifications are documented.

 

Periodically, we retain outside experts to independently verify our coal reserve and our non-reserve coal deposit estimates. The most recent audit by an independent engineering firm of our coal reserve and non-reserve coal deposit estimates was completed by Marshall Miller & Associates, Inc. as of November 30, 2016, and covered a majority of the coal reserves and non-reserve coal deposits that we controlled as of such date. The coal reserve estimates were updated through December 31, 2016 by our internal staff of engineers based upon production data. We intend to continue to periodically retain outside experts to assist management with the verification of our estimates of our coal reserves and non-reserve coal deposits going forward.

 

As of December 31, 2016, we controlled an estimated 256.9 million tons of proven and probable coal reserves and an estimated 196.5 million tons of non-reserve coal deposits. For the year ended December 31, 2016, we did not have any purchases or sales of third-party coal tonnages.

 

Both our estimated proven and probable coal reserves and our non-reserve coal deposits as of December 31, 2016 decreased when compared to the estimated tons reported as of December 31, 2015 due to the sale of our Elk Horn coal leasing business in August 2016. As part of the recent audits performed by Marshall Miller & Associates, Inc., this outside expert performed an independent pro forma economic analysis using industry-accepted guidelines and these were used, in part, to classify tonnage as either proven and probable coal reserves or non-reserve coal deposits, based on current market conditions. In the currently depressed coal market environment, some of our coal deposits that were previously classified as proven and probable coal reserves were re-classified as non-reserve coal deposits due to unfavorable projected economic performance.

 

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Coal Reserves

 

The following table provides information as of December 31, 2016 on the type, amount and ownership of the coal reserves:

 

   Proven and Probable Coal Reserves (1) 
Region  Total (3)   Proven   Probable   Assigned   Unassigned   Owned   Leased   Steam (2)   Metallurgical (2) 
    (in million tons) 
Central Appalachia                                             
Tug River Complex (KY, WV)   21.4    18.3    3.1    17.2    4.2    7.9    13.5    15.4    6.0 
Rob Fork Complex (KY)   7.2    6.1    1.1    7.2    -    1.0    6.2    1.9    5.3 
Rhino Eastern Field (WV) (3)   33.9    19.4    14.5    29.1    4.8    -    33.9    -    33.9 
Rich Mountain Field (WV)   8.2    2.7    5.5    -    8.2    8.2    -    -    8.2 
Total Central Appalachia (5)   70.7    46.5    24.2    53.5    17.2    17.1    53.6    17.3    53.4 
Northern Appalachia                                             
Hopedale Complex (OH)   21.3    17.0    4.3    21.3    -    6.6    14.7    21.3    - 
Sands Hill Complex (OH)   -    -    -    -    -    -    -    -    - 
Leesville Field (OH)   -    -    -    -    -    -    -    -    - 
Springdale Field (PA)   -    -    -    -    -    -    -    -    - 
Total Northern Appalachia (5)   21.3    17.0    4.3    21.3    -    6.6    14.7    21.3    - 
Illinois Basin                                             
Taylorville Field (IL)   111.1    38.9    72.2    -    111.1    -    111.1    111.1    - 
Pennyrile Complex (KY)   29.6    16.0    13.6    29.6    -    -    29.6    29.6    - 
Total Illinois Basin (5)   140.7    54.9    85.8    29.6    111.1    -    140.7    140.7    - 
Western Bituminous                            -                
Castle Valley Complex (UT)   17.9    12.2    5.7    17.9    -    -    17.9    17.9    - 
McClane Canyon Mine (CO) (4)   6.3    4.1    2.2    6.3    -    0.2    6.1    6.3    - 
Total Western Bituminous (5)   24.2    16.3    7.9    24.2    -    0.2    24.0    24.2    - 
Total (5)   256.9    134.7    122.2    128.6    128.3    23.9    233.0    203.5    53.4 
Percentage of total (5)        52.4%   47.6%   50.1%   49.9%   9.3%   90.7%   79.2%   20.8%

 

 

(1)

Represents recoverable tons. The recoverable tonnage estimates take into account mining losses and coal wash plant losses of material from both mining dilution and any non-coal material found within the coal seams. Except for coal expected to be processed and sold on a direct-shipped basis, a specific wash plant recovery factor has been estimated from representative exploration data for each coal seam and applied on a mine-by-mine basis to the estimates. Actual wash plant recoveries vary depending on customer coal quality specifications.

   
(2) For purposes of this table, we have defined metallurgical coal reserves as reserves located in those seams that historically have been of sufficient quality and characteristics to be able to be used in the steel making process. All other coal reserves are defined as steam coal. However, some of the reserves in the metallurgical category can also be used as steam coal.
   
(3) The Rhino Eastern joint venture was dissolved in January 2015. As part of this dissolution, we received approximately 34 million tons of premium metallurgical coal reserves, which we have included in the proven and probable reserves listed above as of December 31, 2016.
   
(4) The McClane Canyon mine was permanently idled as of December 31, 2013.
   
(5) Percentages of totals are calculated based on actual amounts and not the rounded amounts presented in this table.

 

The majority of our leases have an initial term denominated in years but also provide for the term of the lease to continue until exhaustion of the “mineable and merchantable” coal in the lease area so long as the terms of the lease are complied with. Some of our leases have terms denominated in years rather than mine-to-exhaustion provisions, but in all such cases, we believe that the term of years will allow the recoverable reserve to be fully extracted in accordance with our projected mine plan. Consistent with industry practice, we conduct only limited investigations of title to our coal properties prior to leasing. Title to lands and reserves of the lessors or grantors and the boundaries of our leased priorities are not completely verified until we prepare to mine those reserves.

 

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The following table provides information on particular characteristics of our coal reserves as of December 31, 2016:

 

   As Received Basis (1)   Proven and Probable Coal Reserves (2) 
               S02/mm       Sulfur Content 
Region   % Ash    % Sulfur    Btu/lb.    Btu    Total    <1%    1-1.5%    >1.5%    Unknown 
Central Appalachia                       (in million tons) 
Tug River Complex (KY, WV)   9.58%   1.25%   13,084    1.91    21.4    9.3    9.1    2.0    1.0 
Rob Fork Complex (KY)   5.47%   0.96%   13,591    1.42    7.2    6.5    0.5    0.2    - 
Rhino Eastern Field (WV) (3)   4.17%   0.67%   14,035    0.96    33.9    28.8    4.9    -    0.2 
Rich Mountain Field (WV)   7.28%   0.60%   13,235    0.91    8.2    8.2    -    -    - 
Total Central Appalachia   6.26%   0.86%   13,615    1.27    70.7    52.8    14.5    2.2    1.2 
Northern Appalachia                                             
Hopedale Complex (OH)   7.22%   2.45%   14,910    3.28    21.3    -    -    21.3    - 
Sands Hill Complex (OH)   -    -    -    -    -    -    -    -    - 
Total Northern Appalachia   7.22%   2.45%   14,910    3.29    21.3    -    -    21.3    - 
Illinois Basin                                             
Taylorville Field (IL)   7.75%   3.53%   11,057    6.38    111.1    -    -    111.1    - 
Pennyrile Complex (KY)   7.79%   2.53%   11,475    4.42    29.6    -    -    29.6    - 
Total Illinois Basin   7.76%   3.32%   11,145    5.96    140.7    -    -    140.7    - 
Western Bituminous                                             
Castle Valley Complex (UT)   10.63%   0.75%   12,058    1.24    17.9    17.9    -    -    - 
McClane Canyon Mine (CO) (4)   11.19%   0.57%   11,241    1.01    6.3    6.3    -    -    - 
Total Western Bituminous   10.77%   0.70%   11,847    1.19    24.2    24.2    -    -    - 
Total (5)   7.59%   2.33%   12,196    3.82    256.9    77.0    14.5    164.2    1.2 
Percentage of total (5)                            30.0%   5.6%   63.9%   0.5%

 

 

(1) As received basis represents average dry basis analytical test results which are normalized to a moisture content deemed to be representative of the saleable coal product.
   
(2) Represents recoverable tons.
   
(3) The Rhino Eastern joint venture was dissolved in January 2015. As part of this dissolution, we received approximately 34 million tons of premium metallurgical coal reserves, which we have included in the proven and probable reserves listed above as of December 31, 2016.
   
(4) The McClane Canyon mine was permanently idled as of December 31, 2013.
   
(5) Totals and percentages of totals are calculated based on actual amounts and not the rounded amounts presented in this table.

 

Non-Reserve Coal Deposits

 

The following table provides information on our non-reserve coal deposits as of December 31, 2016:

 

   Non-Reserve Coal Deposits 
       Total Tons 
Region   Total Tons    Owned    Leased 
    (in million tons) 
Central Appalachia   46.9    15.6    31.3 
Northern Appalachia   85.6    70.2    15.4 
Illinois Basin   34.0    -    34.0 
Western Bituminous   30.0    -    30.0 
Total   196.5    85.8    110.7 
Percentage of total        43.66%   56.34%

 

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Consistent with industry practice, we conduct only limited investigations of title to our coal properties prior to leasing. Title to lands and non-reserve coal deposits of the lessors or grantors and the boundaries of our leased priorities are not completely verified until we prepare to mine the coal.

 

Office Facilities

 

We lease office space at 424 Lewis Hargett Circle, Lexington, Kentucky for our executives and administrative support staff. We executed an amendment to this lease in 2013 to extend the lease term for five additional years to August 2018.

 

Item 3. Legal Proceedings.

 

We may, from time to time, be involved in various legal proceedings and claims arising out of our operations in the normal course of business. While many of these matters involve inherent uncertainty, we do not believe that we are a party to any legal proceedings or claims that will have a material adverse impact on our business, financial condition or results of operations.

 

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 and Item 104 of Regulation S-K for the year ended December 31, 2016 is included in Exhibit 95.1 to this report.

 

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PART II

 

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

 

Our Limited Partnership Interests

 

Our common units traded on the NYSE under the symbol “RNO” from September 30, 2010 through December 17, 2015. Our common units began trading on the OTCQB under the symbol “RHNO” on December 18, 2015. Our common units were delisted from the NYSE on May 9, 2016. Our common units continue to trade on the OTCQB Marketplace under the ticker symbol “RHNO.”

 

On March 17, 2017, the closing market price for our common units was $4.50 per unit. The following table sets forth the range of the daily high and low sales prices as reported by the NYSE or OTCQB, as applicable, and cash distribution per common unit for the periods indicated. The quotations from the OTCQB reflect inter-dealer prices without retail markup, markdown or commissions and may not represent actual transactions.

 

Beginning with the quarter ended June 30, 2015 and continuing through the quarter ended December 31, 2016, we have suspended the cash distribution for our common units.

 

   Price Range   Common Unit 
   High   Low   Cash Distribution (1) 
Year ended December 31, 2016            
Fourth Quarter  $5.50   $1.78   $0.000 
Third Quarter  $3.05   $1.90   $0.000 
Second Quarter  $3.44   $1.75   $0.000 
First Quarter  $0.49   $0.27   $0.000 
Year ended December 31, 2015               
Fourth Quarter  $1.05   $0.20   $0.000 
Third Quarter  $1.60   $0.63   $0.000 
Second Quarter  $2.43   $1.24   $0.000 
First Quarter  $2.93   $1.77   $0.200 

 

  (1) Represents cash distributions attributable to the quarter. Cash distributions declared in respect of a calendar quarter are paid in the following calendar quarter. The cash distributions have been adjusted as if the 1-for-10 reverse split took place before the date of the earliest transaction reported.

 

As of March 17, 2017, we had outstanding 12,905,799 common units, 1,235,534 subordinated units, 1,500,000 Series A preferred units, and a 0.4% general partner interest and incentive distribution rights (“IDRs”). As of March 17, 2017, Royal Energy Resources, Inc. owned approximately 51.1% of our outstanding common units and 85.9% of our subordinated units and our general partner. Our general partner currently owns a 0.4% general partner interest in us and all of our IDRs.

 

As of March 17, 2017, there were 94 holders of record of our common units. The number of record holders does not include holders of units in “street names” or persons, partnerships, associations, corporations or other entities identified in security position listings maintained by depositories.

 

Cash Distribution Policy

 

We will make a minimum quarterly distribution of $4.45 per common unit (or $17.80 per common unit on an annualized basis) to the extent we have sufficient available cash and when our cash distributions are not suspended. Available cash is generally defined as cash from operations after establishment by our general partner of cash reserves to provide for the conduct of our business, to comply with applicable law, any of our debt instruments or other agreements or to provide for future distributions to unitholders for any one or more of the next four quarters, and payment of costs and expenses, including reimbursement of expenses to our general partner and its affiliates. 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 does not set a limit on the amount of cash reserves that our general partner may establish or the amount of expenses for which our general partner and its affiliates may be reimbursed. Available cash may also include, if our general partner so determines, all or any portion of the cash on hand on the date of determination of available cash for the quarter resulting from working capital borrowings made subsequent to the end of such quarter. We may also borrow to fund distributions in quarters when we generate less available cash than necessary to sustain or grow our cash distributions per unit.

 

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There is no guarantee that we will distribute quarterly cash distributions to our unitholders. Our distribution policy is subject to certain restrictions and may be changed at any time. The reasons for such uncertainties in our stated cash distribution policy include the following factors:

 

    Our cash distribution policy is subject to restrictions on distributions under our credit agreement. Our credit agreement contains financial tests and covenants that we must satisfy. These financial tests and covenants are described in “Part II, Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations—Liquidity and Capital Resources—Credit Agreement.” Should we be unable to satisfy these restrictions or if we are otherwise in default under our credit agreement, we would be prohibited from making cash distributions notwithstanding our cash distribution policy.
     
  Our general partner will have the authority to establish cash reserves for the prudent conduct of our business and for future cash distributions to our unitholders, and the establishment of or increase in those reserves could result in a reduction in cash distributions from levels we currently anticipate pursuant to our stated cash distribution policy. Our partnership agreement does not set a limit on the amount of cash reserves that our general partner may establish.
     
  Prior to making any distribution on the common units, we will reimburse our general partner and its affiliates for all expenses they incur and payments they make on our behalf. Our partnership agreement provides that our general partner will determine in good faith the expenses that are allocable to us. The reimbursement of expenses and payment of fees, if any, to our general partner and its affiliates will reduce the amount of available cash to pay cash distributions to our unitholders.
     
  While our partnership agreement requires us to distribute all of our available cash, our partnership agreement, including provisions requiring us to make cash distributions contained therein, may be amended. Our partnership agreement generally may not be amended during the subordination period without the approval of our public common unitholders. However, our partnership agreement can be amended with the consent of our general partner and the approval of a majority of the outstanding common units after the subordination period has ended.
     
  Even if our cash distribution policy is not modified or revoked, the amount of distributions we pay under our cash distribution policy and the decision to make any distribution is determined by our general partner, taking into consideration the terms of our partnership agreement.
     
  Under Section 17-607 of the Delaware Act, we may not make a distribution if the distribution would cause our liabilities to exceed the fair value of our assets.
     
  We may lack sufficient cash to pay distributions to our unitholders due to cash flow shortfalls attributable to a number of operational, commercial or other factors as well as increases in our operating or selling, general and administrative expenses, principal and interest payments on our outstanding debt, tax expenses, working capital requirements and anticipated cash needs.
     
  If we make distributions out of capital surplus, as opposed to operating surplus, such distributions will result in a reduction in the minimum quarterly distribution and the target distribution levels. However, we do not anticipate that we will make any distributions from capital surplus.
     
  Our ability to make distributions to our unitholders depends on the performance of our subsidiaries and their ability to distribute cash to us. The ability of our subsidiaries to make distributions to us may be restricted by, among other things, the provisions of existing and future indebtedness, applicable state partnership and limited liability company laws and other laws and regulations.

 

Our partnership agreement requires us to distribute all of our available cash each quarter in the following manner:

 

  first, 99.6% to the holders of common units and 0.4% to our general partner, until each common unit has received the minimum quarterly distribution of $4.45 plus any arrearages from prior quarters;

 

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    second, 99.6% to the holders of subordinated units and 0.4% to our general partner, until each subordinated unit has received the minimum quarterly distribution of $4.45; and
     
    third, 99.6% to all unitholders, pro rata, and 0.4% to our general partner, until each unit has received a distribution of $5.1175.

 

If cash distributions to our unitholders exceed $5.1175 per unit in any quarter, our unitholders and our general partner, as the holder of the incentive distribution rights, will receive distributions according to the following percentage allocations:

 

   Marginal Percentage
Interest in
Distributions
 
Total Quarterly Distribution Target Amount  Unitholders   General Partner 
Above $5.1175 up to $5.5625   86.6%   13.4%
Above $5.5625 up to $6.675   76.6%   23.4%
Above $6.675   51.6%   48.4%

 

The percentage interest shown of our general partner includes its 0.4% general partner interest. Our general partner is entitled to 0.4% of all distributions that we make prior to our liquidation. Our partnership agreement provides our general partner the right, but not the obligation, to contribute capital to maintain its 0.4% general partner interest in us if we issue additional units in the future. Thus, if our general partner elects not to make such a capital contribution, its interest will be proportionately reduced.

 

During the subordination period, before we make any quarterly distributions to our subordinated unitholders, our common unitholders are entitled to receive payment of the minimum quarterly distribution plus any arrearages in distributions from prior quarters. The subordination period will end on the first business day after we have earned and paid at least (i) $17.80 (the minimum quarterly distribution on an annualized basis) on each outstanding unit and the corresponding distribution on our general partner’s general partner interest for each of three consecutive, non-overlapping four quarter periods ending after September 30, 2013 or (ii) $26.70 (150.0% of the annualized minimum quarterly distribution) on each outstanding unit and the corresponding distributions on our general partner’s general partner interest and the incentive distribution rights for the four-quarter period immediately preceding that date. The subordination period also will end upon the removal of our general partner other than for cause if no subordinated units or common units held by the holders of subordinated units or their affiliates are voted in favor of that removal. When the subordination period ends, all subordinated units will convert into common units on a one-for-one basis, and all common units thereafter will no longer be entitled to arrearages.

 

We will pay any distributions on or about the 15th day of each of February, May, August and November to holders of record on or about the 1st day of each such month. If the distribution date does not fall on a business day, we will make the distribution on the business day immediately preceding the indicated distribution date.

 

Beginning with the quarter ended June 30, 2015 we have suspended the cash distribution for our common units. For each of the quarters ended September 30, 2014 and December 31, 2014 and March 31, 2015, we announced cash distributions at levels lower than the minimum quarterly distribution. Pursuant to our partnership agreement, our common units accrue arrearages every quarter when the distribution level is below the minimum level of $4.45 per unit. We have accumulated arrearages at December 31, 2016 related to the common unit distribution of approximately $207.4 million. In addition, we have not paid any distributions on our subordinated units for any quarter after the quarter ended March 31, 2012. Our subordinated units do not accrue arrearages for unpaid distributions.

 

Distributions on Preferred Units

 

On December 30, 2016, our general partner amended our partnership agreement to create, authorize and issue the Series A preferred units, and we issued 1,500,000 Series A preferred units.

 

The Series A preferred units are a new class of equity security that rank senior to all classes or series of our equity securities with respect to distribution rights and rights upon liquidation. The holders of the Series A preferred units are entitled to receive annual distributions equal to the greater of (i) 50% of the CAM Mining free cash flow (as defined below) and (ii) an amount equal to the number of outstanding Series A preferred units multiplied by $0.80. “CAM Mining free cash flow” is defined in our partnership agreement as (i) the total revenue of our Central Appalachia business segment, minus (ii) the cost of operations (exclusive of depreciation, depletion and amortization) for our Central Appalachia business segment, minus (iii) an amount equal to $6.50, multiplied by the aggregate number of met coal and steam coal tons sold by us from our Central Appalachia business segment. If we fail to pay any or all of the distributions in respect of the Series A preferred units, such deficiency will accrue until paid in full and we will not be permitted to pay any distributions on our partnership interests that rank junior to the Series A preferred units, including the common units. The Series A preferred units will be liquidated in accordance with their capital accounts and upon liquidation will be entitled to distributions of property and cash in accordance with the balances of their capital accounts prior to such distributions to equity securities that rank junior to the Series A preferred units.

 

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Item 6. Selected Financial Data

 

The Registrant is a smaller reporting company and is not required to provide this information.

 

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

 

The following discussion of the historical financial condition and results of operations should be read in conjunction with the historical financial statements and accompanying notes included elsewhere in this report. In addition, this discussion includes forward-looking statements that are subject to risks and uncertainties that may result in actual results differing from statements we make. See “Cautionary Note Regarding Forward- Looking Statements.” Factors that could cause actual results to differ include those risks and uncertainties discussed in Part I, Item 1A. “Risk Factors.”

 

In August 2016, we sold our Elk Horn coal leasing company (“Elk Horn”) to a third party for total cash consideration of $12.0 million. Our consolidated statements of operations and comprehensive income have been retrospectively adjusted to reclassify our Elk Horn operations to discontinued operations for the years ended December 31, 2016 and 2015.

 

Overview

 

We are a diversified energy limited partnership formed in Delaware that is focused on coal and energy related assets and activities, including energy infrastructure investments. We produce, process and sell high quality coal of various steam and metallurgical grades. We market our steam coal primarily to electric utility companies as fuel for their steam powered generators. Customers for our metallurgical coal are primarily steel and coke producers who use our coal to produce coke, which is used as a raw material in the steel manufacturing process. In addition, we have expanded our business to include infrastructure support services, as well as other joint venture investments to provide for the transportation of hydrocarbons and drilling support services in the Utica Shale region. We have also invested in joint ventures that provide sand for fracking operations to drillers in the Utica Shale region and other oil and natural gas basins in the United States.

 

We have a geographically diverse asset base with coal reserves located in Central Appalachia, Northern Appalachia, the Illinois Basin and the Western Bituminous region. As of December 31, 2016, we controlled an estimated 256.9 million tons of proven and probable coal reserves, consisting of an estimated 203.5 million tons of steam coal and an estimated 53.4 million tons of metallurgical coal. In addition, as of December 31, 2016, we controlled an estimated 196.5 million tons of non-reserve coal deposits. Both our estimated proven and probable coal reserves and non-reserve coal deposits as of December 31, 2016 decreased when compared to the estimated tons and deposits reported as of December 31, 2015 due to the sale of our Elk Horn coal leasing business in August 2016. As part of the recent audits of our coal reserves and deposits performed by Marshall Miller & Associates, Inc., this outside expert performed an independent pro forma economic analysis using industry-accepted guidelines and this was used, in part, to classify tonnage as either proven and probable coal reserves or non-reserve coal deposits, based on current market conditions.

 

We operate underground and surface mines located in Kentucky, Ohio, West Virginia and Utah. The number of mines that we operate will vary from time to time depending on a number of factors, including the existing demand for and price of coal, depletion of economically recoverable reserves and availability of experienced labor. In the third quarter of 2015, we temporarily idled a majority of our Central Appalachia operations due to ongoing weak coal market conditions for met and steam coal produced from this region. We resumed mining operations at all of our Central Appalachia operations in 2016 to fulfill customer contracts that we secured for 2016 and 2017.

 

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Our principal business strategy is to safely, efficiently and profitably produce and sell both steam and metallurgical coal from our diverse asset base in order to resume, and, over time, increase our quarterly cash distributions. In addition, we intend to continue to expand and potentially diversify our operations through strategic acquisitions, including the acquisition of long-term, cash generating natural resource assets. We believe that such assets will allow us to grow our cash available for distribution and enhance stability of our cash flow.

 

For the year ended December 31, 2016, we generated revenues of approximately $170.8 million and a net loss from continuing operations of approximately $12.0 million. For the year ended December 31, 2016, we produced approximately 3.3 million tons of coal and sold approximately 3.3 million tons of coal, approximately 90% of which were pursuant to long-term supply contracts.

 

Current Liquidity and Outlook

 

As of December 31, 2016, our available liquidity was $13.0 million, including cash on hand of $0.1 million and $12.9 million available under our amended and restated credit agreement. On May 13, 2016, we entered into a Fifth Amendment of our amended and restated agreement that initially extended the term of the senior secured credit facility to July 31, 2017. Per the Fifth Amendment, the term of the credit facility automatically extended to December 31, 2017 when the revolving credit commitments were reduced to $55 million or less as of December 31, 2016. The Fifth Amendment also immediately reduced the revolving credit commitments under the credit facility to a maximum of $75 million and maintains the amount available for letters of credit at $30 million. As of December 31, 2016, we met the requirements to extend the maturity date of the credit facility to December 31, 2017. In December 2016, we entered into a Seventh Amendment of our amended and restated credit agreement. The Seventh Amendment immediately reduced the revolving credit commitments by $11.0 million and provides for additional revolving credit commitment reductions of $2.0 million each on June 30, 2017 and September 30, 2017. The Seventh Amendment further reduces the revolving credit commitments over time on a dollar-for-dollar basis for the net cash proceeds received from any asset sales after the Seventh Amendment date once the aggregate net cash proceeds received exceeds $2.0 million. For more information about our amended and restated credit agreement, please read Part 1, Item 1. —Recent Developments-Amendments to Amended and Restated Credit Agreement.”

 

Since the current maturity date of our credit facility is December 31, 2017, we are unable to demonstrate that we have sufficient liquidity to operate our business over the next twelve months from the date of filing our Annual Report on Form 10-K and thus substantial doubt is raised about our ability to continue as a going concern. Accordingly, our independent registered public accounting firm has included an emphasis paragraph with respect to our ability to continue as a going concern in its report on our consolidated financial statements for the year ended December 31, 2016. The presence of the going concern emphasis paragraph in our auditors’ report may have an adverse impact on our relationship with third parties with whom we do business, including our customers, vendors, lenders and employees, making it difficult to raise additional debt or equity financing to the extent needed and conduct normal operations. As a result, our business, results of operations, financial condition and prospects could be materially adversely affected.

 

Since our credit facility has an expiration date of December 2017, we determined that our credit facility debt liability of $10.0 million at December 31, 2016 should be classified as a current liability on our consolidated statements of financial position. The classification of our credit facility balance as a current liability raises substantial doubt of our ability to continue as a going concern for the next twelve months. We are considering alternative financing options that could result in a new long-term credit facility. However, we may be unable to complete such a transaction on terms acceptable to us or at all. If we are unable to extend the expiration date of our credit facility, we will have to secure alternative financing to replace our credit facility by the expiration date of December 2017 in order to continue our business operations. If we are unable to extend the expiration date of our credit facility or secure a replacement facility, we will lose a primary source of liquidity, and we may not be able to generate adequate cash flow from operations to fund our business, including amounts that may become due under our credit facility. Furthermore, although met coal prices and demand have improved in recent months, if weak demand and low prices for steam coal persist and if met coal prices and demand weaken, we may not be able to continue to give the required representations or meet all of the covenants and restrictions included in our credit facility. If we violate any of the covenants or restrictions in our amended and restated credit agreement, including the maximum leverage ratio, some or all of our indebtedness may become immediately due and payable, and our lenders’ commitment to make further loans to us may terminate. If we are unable to give a required representation or we violate a covenant or restriction, then we will need a waiver from our lenders in order to continue to borrow under our amended and restated credit agreement. Although we believe our lenders loans are well secured under the terms of our amended and restated credit agreement, there is no assurance that the lenders would agree to any such waiver. Failure to obtain financing or to generate sufficient cash flow from operations could cause us to further curtail our operations and reduce our spending and to alter our business plan. We may also be required to consider other options, such as selling additional assets or merger opportunities, and depending on the urgency of our liquidity constraints, we may be required to pursue such an option at an inopportune time. If we are not able to fund our liquidity requirements for the next twelve months, we may not be able to continue as a going concern. For more information about our liquidity and our credit facility, please read “Part II, Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations —Liquidity and Capital Resources.”

 

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We continue to take measures, including the suspension of cash distributions on our common and subordinated units and cost and productivity improvements, to enhance and preserve our liquidity so that we can fund our ongoing operations and necessary capital expenditures and meet our financial commitments and debt service obligations.

 

Recent Developments

 

Sale of our General Partner by Wexford

 

On January 21, 2016 and March 17, 2016, Royal acquired from Wexford all of the issued and outstanding membership interests of our general partner, 676,912 of our issued and outstanding common units and 945,525 issued and outstanding subordinated units. Royal is a publicly traded company listed on the OTC market (OTCQB: ROYE) and is focused on the acquisition of coal, natural gas and renewable energy assets that are profitable at current distressed prices. Immediately subsequent to the consummation of the transaction, the following members of the board of directors of our general partner tendered their resignations effective immediately: Mark Zand, Philip Braunstein, Ken Rubin, Arthur Amron, Douglas Lambert and Mark Plaumann. As the owner of our general partner, Royal has the right to appoint the members of the board of directors of our general partner and so appointed the following individuals as new directors to fill the vacancies resulting from the resignations: William Tuorto, Ronald Phillips, Michael Thompson, Ian Ganzer (who subsequently resigned in September 2016), Douglas Holsted, Brian Hughs and David Hanig.

 

On March 21, 2016, we and Royal entered into a securities purchase agreement pursuant to which we issued 6,000,000 of our common units to Royal in a private placement at $1.50 per common unit for an aggregate purchase price of $9.0 million. Royal paid us $2.0 million in cash and delivered the Rhino Promissory Note payable to us in the amount of $7.0 million. On May 13, 2016 and September 30, 2016, Royal paid us $3.0 million and $2.0 million, respectively, on the promissory note. The final installment on the promissory note of $2.0 million was due on or before December 31, 2016. However, on December 30, 2016, we modified the Securities Purchase Agreement with Royal to extend the due date of the final $2.0 million payment to December 31, 2018. Please read “—Letter Agreement Regarding Rhino Promissory Note and Weston Promissory Note.” In the event the disinterested members of the board of directors of our general partner determine that we do not need the capital that would be provided by the final installment, we have the option to rescind Royal’s purchase of 1,333,333 common units and the applicable installment will not be payable (each, a “Rescission Right”). If we fail to exercise a Rescission Right, we have the option to repurchase 1,333,333 of our common units at $3.00 per common unit from Royal. The Repurchase Option terminates on December 31, 2017. Royal’s obligation to pay any installment of the promissory note is subject to certain conditions, including that we have entered into an agreement to extend the amended and restated credit agreement, as amended, to a date no sooner than December 31, 2017. In the event such conditions are not satisfied as of the installment due date, Royal has the right to cancel the remaining unpaid balance of the promissory note in exchange for the surrender of such number of common units equal to the principal balance of the promissory note divided by $1.50.

 

Pursuant to the Securities Purchase Agreement, on March 21, 2016, we and Royal entered into a registration rights agreement. The registration rights agreement grants Royal piggyback registration rights under certain circumstances with respect to the common units issued to Royal pursuant to the Securities Purchase Agreement.

 

Option Agreement

 

On December 30, 2016, we entered into the Option Agreement with Royal, Rhino Holdings, and our general partner. Upon execution of the Option Agreement, we received a Call Option from Rhino Holdings to acquire substantially all of the outstanding common stock of Armstrong Energy that is owned by investment partnerships managed by Yorktown, representing approximately 97% of the outstanding common stock of Armstrong Energy. Armstrong Energy is a coal producing company with approximately 554 million tons of proven and probable reserves and six mines located in the Illinois Basin in western Kentucky as of September 30, 2016. The Option Agreement stipulates that we can exercise the Call Option no earlier than January 1, 2018 and no later than December 31, 2019. In exchange for Rhino Holdings granting us the Call Option, we issued 5.0 million Call Option Premium Units to Rhino Holdings upon the execution of the Option Agreement. The Option Agreement stipulates we can exercise the Call Option and purchase the common stock of Armstrong Energy in exchange for a number of common units to be issued to Rhino Holdings, which when added with the Call Option Premium Units, will result in Rhino Holdings owning 51% of the fully diluted common units of us. The purchase of Armstrong Energy through the exercise of the Call Option would also require Royal to transfer a 51% ownership interest in our general partner to Rhino Holdings. Our ability to exercise the Call Option is conditioned upon (i) sixty (60) days having passed since the entry by Armstrong Energy into an agreement with its bondholders to restructure its bonds and (ii) the amendment of our revolving credit facility to permit the acquisition of Armstrong Energy.

 

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The Option Agreement also contains a Put Option granted by us to Rhino Holdings whereby Rhino Holdings has the right, but not the obligation, to cause us to purchase substantially all of the outstanding common stock of Armstrong Energy from Rhino Holdings under the same terms and conditions discussed above for the Call Option. The exercise of the Put Option is dependent upon (i) the entry by Armstrong Energy into an agreement with its bondholders to restructure its bonds and (ii) the termination and repayment of any outstanding balance under our revolving credit facility.

 

The Option Agreement contains customary covenants, representations and warranties and indemnification obligations for losses arising from the inaccuracy of representations or warranties or breaches of covenants contained in the Option Agreement, the Seventh Amendment (defined below) and the GP Amendment (defined below). Upon the request by Rhino Holdings, we will also enter into a registration rights agreement that provides Rhino Holdings with the right to demand two shelf registration statements and registration statements on Form S-1, as well as piggyback registration rights for as long as Rhino Holdings owns at least 10% of the outstanding common units.

 

Pursuant to the Option Agreement, the Second Amended and Restated Limited Liability Company Agreement of our general partner was amended. Pursuant to the GP Amendment, Mr. Bryan H. Lawrence was appointed to the board of directors of our general partner as a designee of Rhino Holdings and Rhino Holdings has the right to appoint an additional independent director. Rhino Holdings has the right to appoint two members to the board of directors of our general partner for as long as it continues to own 20% of the common units on an undiluted basis. The GP Amendment also provided Rhino Holdings with the authority to consent to any delegation of authority to any committee of the board of our general partner. Upon the exercise of the Call Option or the Put Option, the Second Amended and Restated Limited Liability Company Agreement of our general partner, as amended, will be further amended to provide that Royal and Rhino Holdings will each have the ability to appoint three directors and that the remaining director will be the chief executive officer of our general partner unless agreed otherwise.

 

The Option Agreement superseded and terminated the equity exchange agreement entered into on September 30, 2016 by and among Royal, Rhino Holdings, an entity wholly owned by certain investment partnerships managed by Yorktown, and our general partner.

 

Series A Preferred Unit Purchase Agreement

 

On December 30, 2016, we entered into a Series A Preferred Unit Purchase Agreement with Weston Energy LLC (“Weston”), an entity wholly owned by certain investment partnerships managed by Yorktown, and Royal. Under the Preferred Unit Agreement, Weston and Royal agreed to purchase 1,300,000 and 200,000, respectively, of Series A preferred units representing limited partner interests in us at a price of $10.00 per Series A preferred unit. The Series A preferred units have the preferences, rights and obligations set forth in our Fourth Amended and Restated Agreement of Limited Partnership, which is described below. In exchange for the Series A preferred units, Weston and Royal paid cash of $11.0 million and $2.0 million, respectively, to us and Weston assigned to us a $2.0 million note receivable from Royal originally dated September 30, 2016. Please read “—Letter Agreement Regarding Rhino Promissory Note and Weston Promissory Note.”

 

The Preferred Unit Agreement contains customary representations, warrants and covenants, which include among other things, that, for as long as the Series A preferred units are outstanding, we will cause CAM Mining, one of our subsidiaries, to conduct its business in the ordinary course consistent with past practice and use reasonable best efforts to maintain and preserve intact its current organization, business and franchise and to preserve the rights, franchises, goodwill and relationships of its employees, customers, lenders, suppliers, regulators and others having business relationships with CAM Mining.

 

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The Preferred Unit Agreement stipulates that upon the request of the holder of the majority of our common units following their conversion from Series A preferred units, as outlined in our partnership agreement, we will enter into a registration rights agreement with such holder. Such majority holder has the right to demand two shelf registration statements and registration statements on Form S-1, as well as piggyback registration rights.

 

On January 27, 2017, Royal sold 100,000 of its Series A preferred units to Weston and its other 100,000 Series A preferred units to another third party.

 

Letter Agreement Regarding Rhino Promissory Note and Weston Promissory Note

 

On December 30, 2016, we entered into a letter agreement with Royal whereby the maturity dates of the Weston Promissory Note and the final installment payment of the Rhino Promissory Note were extended to December 31, 2018. The letter agreement further provides that the aggregate $4.0 million balance of the Weston Promissory Note and Rhino Promissory Note may be converted at Royal’s option into a number of shares of Royal’s common stock equal to the outstanding balance multiplied by seventy-five percent (75%) of the volume-weighted average closing price of Royal’s common stock for the 90 days preceding the date of conversion (“Royal VWAP”), subject to a minimum Royal VWAP of $3.50 and a maximum Royal VWAP of $7.50.

 

Fourth Amended and Restated Partnership Agreement of Limited Partnership

 

On December 30, 2016, our general partner amended our partnership agreement to create, authorize and issue the Series A preferred units.

 

The Series A preferred units are a new class of equity security that rank senior to all classes or series of our equity securities with respect to distribution rights and rights upon liquidation. The holders of the Series A preferred units shall be entitled to receive annual distributions equal to the greater of (i) 50% of the CAM Mining free cash flow (as defined below) and (ii) an amount equal to the number of outstanding Series A preferred units multiplied by $0.80. “CAM Mining free cash flow” is defined in our partnership agreement as (i) the total revenue of our Central Appalachia business segment, minus (ii) the cost of operations (exclusive of depreciation, depletion and amortization) for our Central Appalachia business segment, minus (iii) an amount equal to $6.50, multiplied by the aggregate number of met coal and steam coal tons sold by us from our Central Appalachia business segment. If we fail to pay any or all of the distributions in respect of the Series A preferred units, such deficiency will accrue until paid in full and we will not be permitted to pay any distributions on our partnership interests that rank junior to the Series A preferred units, including our common units. The Series A preferred units will be liquidated in accordance with their capital accounts and upon liquidation will be entitled to distributions of property and cash in accordance with the balances of their capital accounts prior to such distributions to equity securities that rank junior to the Series A preferred units.

 

The Series A preferred units vote on an as-converted basis with the common units, and we will be restricted from taking certain actions without the consent of the holders of a majority of the Series A preferred units, including: (i) the issuance of additional Series A preferred units, or securities that rank senior or equal to the Series A preferred units; (ii) the sale or transfer of CAM Mining or a material portion of its assets; (iii) the repurchase of common units, or the issuance of rights or warrants to holders of common units entitling them to purchase common units at less than fair market value; (iv) consummation of a spin off; (v) the incurrence, assumption or guaranty of indebtedness for borrowed money in excess of $50.0 million except indebtedness relating to entities or assets that are acquired by us or our affiliates that is in existence at the time of such acquisition or (vi) the modification of CAM Mining’s accounting principles or the financial or operational reporting principles of our Central Appalachia business segment, subject to certain exceptions.

 

Elk Horn Coal Leasing Disposition

 

In August 2016, we entered into an agreement to sell our Elk Horn coal leasing company to a third party for total cash consideration of $12.0 million. We received $10.5 million in cash consideration upon the closing of the Elk Horn transaction and the remaining $1.5 million of consideration will be paid in ten equal monthly installments of $150,000 on the 20th of each calendar month beginning on September 20, 2016. Elk Horn is a coal leasing company located in eastern Kentucky that provided us with coal royalty revenues from coal properties owned by Elk Horn and leased to third-party operators. As of December 31, 2015, Elk Horn controlled approximately 100 million tons of proven and probable steam coal reserves. During the second quarter of 2016, we evaluated the Elk Horn assets for potential impairment based upon the initial purchase price offered by the buyer and the continued deterioration of the Central Appalachia steam coal markets that had adversely affected Elk Horn’s financial results. Our impairment analysis determined that a potential impairment existed since the carrying amount of the Elk Horn long-lived asset group exceeded the cash flows that would be generated from the purchase price offered from the buyer. Based on a market approach used to estimate the fair value of the Elk Horn long-lived asset group, we recorded total asset impairment charges of approximately $118.7 million related to Coal properties as of June 30, 2016. The disposal of the Elk Horn assets and liabilities in August 2016 resulted in an additional loss of $1.2 million. The total loss of $119.9 million from the Elk Horn disposal is recorded as discontinued operations along with the previous operating results of Elk Horn that have been reclassified for the years ended December 31, 2016 and 2015.

 

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Amended and Restated Credit Agreement Amendments

 

On March 17, 2016, our Operating Company, as borrower, and we and certain of our subsidiaries, as guarantors, entered into a Fourth amendment of our Amended and Restated Credit Agreement. The Fourth Amendment amended the definition of change of control in the Amended and Restated Credit Agreement to permit Royal to purchase the membership interests of our general partner.

 

On May 13, 2016, we entered into the Fifth Amendment of the Amended and Restated Credit Agreement, which extended the term to July 31, 2017.

 

In July 2016, we entered into a Sixth Amendment of our amended and restated senior secured credit facility that permitted the sale of Elk Horn that was discussed earlier.

 

In December, 2016, we entered into a Seventh Amendment of our amended and restated credit agreement. The Seventh Amendment allows for the Series A preferred units discussed above. The Seventh Amendment immediately reduces the revolving credit commitments by $11.0 million and provides for additional revolving credit commitment reductions of $2.0 million each on June 30, 2017 and September 30, 2017. A condition precedent to the effectiveness of the Seventh Amendment was the receipt of the $13.0 million of cash proceeds received by us from the issuance of the Series A preferred units discussed above, which was used to repay outstanding borrowings under the revolving credit facility. Per the Seventh Amendment, the receipt of $13.0 million cash proceeds fulfills the required Royal equity contributions as outlined in the previous amendments to our credit agreement. (See “—Liquidity and Capital Resources—Amended and Restated Credit Agreement” for further details on the debt amendments).

 

Delisting of Common Units from NYSE

 

On December 17, 2015, the NYSE notified us that the NYSE had determined to commence proceedings to delist our common units from the NYSE as a result of our failure to comply with the continued listing standard set forth in Section 802.01B of the NYSE Listed Company Manual to maintain an average global market capitalization over a consecutive 30 trading-day period of at least $15 million for our common units. The NYSE also suspended the trading of our common units at the close of trading on December 17, 2015.

 

On January 4, 2016, we filed an appeal with the NYSE to review the suspension and delisting determination of our common units. The NYSE held a hearing regarding our appeal on April 20, 2016 and affirmed its prior decision to delist our common units.

 

On April 27, 2016, the NYSE filed with the SEC a notification of removal from listing and registration on Form 25 to delist our common units and terminate the registration of our common units under Section 12(b) of the Securities Exchange Act of 1934. The delisting became effective on May 9, 2016. Our common units trade on the OTCQB Marketplace under the ticker symbol “RHNO.”

 

We are exploring the possibility of listing our common units on the NASDAQ Stock Market (“NASDAQ”), pending our capability to meet the NASDAQ initial listing standards.

 

Reverse Unit Split

 

On April 18, 2016, we completed a 1-for-10 reverse split on our common units and subordinated units. Pursuant to the reverse split, common unitholders received one common unit for every 10 common units owned on April 18, 2016 and subordinated unitholders received one subordinated unit for every 10 subordinated units owned on April 18, 2016. Any fractional units resulting from the reverse unit split were rounded to the nearest whole unit. The reverse unit split was intended to increase the market price per unit of our common units in order to comply with the NYSE’s continued listing standards.

 

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Distribution Suspension

 

Beginning with the quarter ended June 30, 2015 and continuing through the quarter ended December 31, 2016, we have suspended the cash distribution on our common units. For each of the quarters ended September 30, 2014, December 31, 2014 and March 31, 2015, we announced cash distributions per common unit at levels lower than the minimum quarterly distribution. We have not paid any distribution on our subordinated units for any quarter after the quarter ended March 31, 2012. The distribution suspension and prior reductions were the result of prolonged weakness in the coal markets, which has continued to adversely affect our cash flow.

 

Pursuant to our partnership agreement, our common units accrue arrearages every quarter when the distribution level is below the minimum level of $4.45 per unit. Since our distributions for the quarters ended September 30, 2014, December 31, 2014 and March 31, 2015 were below the minimum level and we altogether suspended the distribution beginning with the quarter ended June 30, 2015, we have accumulated arrearages at December 31, 2016 related to the common unit distribution of approximately $207.4 million.

 

Asset Impairments-2016

 

We performed a comprehensive review of our current coal mining operation as well as potential future development projects as of December 31, 2016 to ascertain any potential impairment losses. Based on the impairment analysis, we concluded that none of the coal properties, mine development costs or other coal mining equipment and related facilities were impaired at December 31, 2016. However, for the year ended December 31, 2016, we recorded $2.6 million of asset impairment losses and related charges associated with the 2015 sale of the Deane mining complex. Of the total $2.6 million non-cash impairment and other non-cash charges incurred, approximately $2.0 million related to impairment of the note receivable that was recorded in 2015 relating to the sale of the Deane mining complex. The additional $0.6 million impairment related to other non-recoverable items associated with the sale of the Deane mining complex. The $2.6 million asset impairment charge/loss for the Deane mining complex is recorded on the Asset impairment and related charges line of the consolidated statements of operations and comprehensive income.

 

Taylorville Land Sale

 

On December 30, 2015, we completed the sale of our land surface rights for our Taylorville property in central Illinois for approximately $7.2 million in net proceeds. The sale agreement allows us to retain the mining permit and control of the proven and probable coal reserves at the Taylorville property as we have the option to repurchase the rights to the land within seven years from the date of the sale agreement. We used the proceeds from the sale of the Taylorville property to reduce the outstanding balance on our credit facility. In accordance with appropriate accounting guidance, since we have the option to repurchase the rights to the land, the transaction has been accounted for as a financing arrangement rather than a sale.

 

Asset Impairments-2015

 

As the prolonged weakness in the U.S. coal markets continued during 2015, we performed a comprehensive review of our current coal mining operations as well as potential future development projects to ascertain any potential impairment losses. We identified various properties, projects and operations that were potentially impaired based upon changes in its strategic plans, market conditions or other factors, specifically in Northern Appalachia where market conditions related to our operations deteriorated in the fourth quarter of 2015. We believe that an oversupply of coal being produced in Northern Appalachia has contributed to depressed coal prices from this region. We believe the oversupply of coal has been created due to historically low natural gas prices in this region, which competes with coal as a source of electricity generation. Utilities have chosen cheap natural gas for electricity generation over coal and, additionally, we believe the amount that the utilities’ power plants have been dispatched for electricity generation has fallen due to low electricity demand. The production of natural gas from the Utica Shale and Marcellus Shale regions that are located within the Northern Appalachian region have kept natural gas prices low and larger coal producers have low-cost long-wall mines in Northern Appalachia that can compete to sell lower priced coal to utilities that still require coal supplies in this region. We believe this combination of factors have decreased coal prices in Northern Appalachia to levels where certain current operations as well as future plans for the development of the Leesville Field (see below) will be unprofitable in the near term. In addition to impairment charges related to certain Northern Appalachia operations, we also recorded asset impairment and related charges for the sale of the Deane mining complex, the sale of the Cana Woodford oil and natural gas investment and an impairment loss for intangible assets that are also discussed herein. We recorded approximately $31.6 million of total asset impairment and related charges for the year ended December 31, 2015, which is recorded on the Asset impairment and related charges line of the consolidated statements of operations and comprehensive income.

 

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Hopedale Mining Complex

 

We own the Hopedale mining complex located in Northern Appalachia that includes an underground mine, preparation plant and full-service rail loadout facility. Hopedale had long-term coal sales contracts with two utility customers that officially expired at the end of 2015, but had carry-over provisions for contracted coal shipments that were not delivered in 2015 and were shipped in 2016. These carry-over tons under these sales contracts have prices well above current market levels for coal being sold in this region, but do not constitute annual coal sales volumes that Hopedale has historically been able to sell. We have been unsuccessful in securing any contracted sales business at profitable prices for Hopedale coal to replace these expiring sales contracts due to the depressed Northern Appalachia coal market conditions discussed above. Based upon these factors, we performed a detailed analysis of potential impairment for the Hopedale mining complex as of December 31, 2015. Our projection of future undiscounted net cash flows to be generated from the Hopedale mining complex indicated that a potential impairment existed since the carrying amount of the long-lived asset group at the Hopedale mining complex exceeded the sum of the projected undiscounted net cash flows. Thus, we performed a further analysis to determine what, if any, impairment existed for the Hopedale mining complex asset group. We utilized a discounted cash flow method (i.e. income approach) to estimate the fair value of the Hopedale mining complex. Based on this analysis, we recorded total asset impairment and related charges of $19.0 million for the Hopedale mining complex for the year ended December 31, 2015.

 

Sands Hill Mining Complex

 

We own the Sands Hill mining complex in Northern Appalachia that includes two surface coal mines located near Hamden, Ohio. The infrastructure at Sands Hill includes a coal preparation plant along with a river front barge and dock facility on the Ohio River. Coal produced at Sands Hill is primarily trucked to local industrial customers in the southeastern region of Ohio. In addition to coal production, limestone aggregate is also produced at Sands Hill as the process of removing overburden to access the coal seams includes the removal of high quality limestone. The Sands Hill complex includes limestone processing facilities that crush and size the limestone for sale to local customers. Sands Hill had contracted coal sales through the end of 2016 from its surface coal mine operations, but no contracted coal sales beyond this date. Limestone is sold on a non-contracted basis from Sands Hill’s operation.

 

During 2015, we contracted with a third-party engineering firm to perform an audit of our coal mineral. As part of the third-party expert’s audit, they performed an independent pro forma economic analysis using industry-accepted guidelines and these were used, in part, to classify coal mineral as either proven and probable coal reserves or non-reserve coal deposits, based on current market conditions. In the depressed Northern Appalachia coal market environment described above, a majority of the Sands Hill coal mineral that had previously been classified as proven and probable coal reserves was re-classified as non-reserve coal deposits as of December 31, 2015 due to unfavorable projected economic performance. Our long-term plan had previously included the eventual development of underground coal reserves at Sands Hill, which were reclassified to non-reserve coal deposits as of December 31, 2015 per the discussion above. However, due to the lack of contracted sales beyond year-end 2016 and the depressed Northern Appalachia coal market discussed above, we decided as of December 31, 2015 to no longer pursue the development of the underground coal deposits at Sands Hill. Thus, we will cease surface coal mining during the second quarter of 2017 when our Sands Hill contracted coal sales are fulfilled. We currently plan to continue limestone sales into 2017 since adequate limestone inventory will remain once coal mining has ceased. Based upon the factors that led to our decision to discontinue coal mining at Sands Hill, we performed a detailed analysis of potential impairment for the Sands Hill mining complex.

 

Our projection of future undiscounted net cash flows to be generated from the Sands Hill mining complex indicated that a potential impairment existed since the carrying amount of the long-lived asset group at the Sands Hill mining complex exceeded the sum of the projected undiscounted net cash flows. Thus, we performed a further analysis to determine what, if any, impairment existed for the Sands Hill mining complex asset group. We utilized a discounted cash flow method (i.e. income approach) to estimate the fair value of the Sands Hill mining complex. Based on this analysis, we recorded total asset impairment and related charges of $5.7 million for the Sands Hill mining complex for the year ended December 31, 2015.

 

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Leesville Field

 

We own the Leesville field that is located in the Northern Appalachia coal region in eastern Ohio and is approximately 20 miles north of our Hopedale mining complex. The Leesville field is an undeveloped property that contains approximately 27.9 million tons of coal mineral that was classified as non-reserve coal deposits as of December 31, 2015. Prior to 2015, the Leesville field coal mineral had been classified as proven and probable coal reserves. The Leesville field coal mineral that had previously been classified as proven and probable coal reserves was re-classified as non-reserve coal deposits due to unfavorable projected economic performance based upon the third party engineering firm’s audit of our coal mineral that was discussed above. Our long-term plan had included the eventual development of Leesville field to supplement the production from our nearby Hopedale mining complex because the coal qualities at Leesville closely matched the coal qualities at Hopedale. However, due to the recent downturn in the coal markets in Northern Appalachia discussed above, the reclassification of the Leesville field coal mineral to non-reserve coal deposits and the difficult economic conditions being experienced at Hopedale discussed above, we decided to reevaluate our plans for the Leesville field and examine this undeveloped property for potential impairment.

 

We believe that the Leesville field mineral would be uneconomic to produce in current market conditions, which are not expected to improve in the near future, and would not produce positive undiscounted net cash flows. Thus, this fact pattern indicated that a potential impairment existed since the carrying amount of the long-lived asset group at Leesville exceeded the sum of any projected undiscounted net cash flows. We analyzed the Leesville asset group and determined the fair value of the Leesville asset group should be based on any compensation that could be received by us from selling the assets to a third party in the current marketplace since it would be uneconomic to develop this project in the current market environment. Based on the current depressed state of the Northern Appalachia coal markets, we determined the Leesville field asset group had zero value as of December 31, 2015. We recorded total asset impairment and related charges of $3.5 million for the Leesville field for the year ended December 31, 2015.

 

Deane Mining Complex Sale

 

On October 30, 2015, we executed a binding letter of intent with a third party for the purchase of our Deane mining complex. The sale of the Deane mining complex was completed on December 30, 2015. The Deane mining complex is located in eastern Kentucky and includes one underground mine that was idle during 2015. The infrastructure at the Deane mining complex consists of a preparation plant and a unit train loadout facility. The sale of the Deane complex transferred the underground mine, related equipment, the preparation plant and loadout facility in exchange for $2.0 million in the form of a promissory note receivable from the third party, while we also retained the mineral rights for the proven and probable steam coal reserves at this complex. The Deane mining complex sale also included a royalty agreement with the third party pursuant to which we will collect future royalties for coal mined and sold from the Deane complex. The sale of the Deane mining complex also relieved us of significant reclamation liabilities and bonding requirements. For third quarter 2015 financial reporting purposes, we evaluated the appropriate held for sale accounting criteria to determine if the Deane mining complex should be classified as held for sale as of September 30, 2015. Based on this evaluation, we determined the Deane mining complex met the held for sale criteria at September 30, 2015 and, accordingly, the Deane mining complex asset group was written down to its estimated fair value of $2.0 million. Due to the determination that the Deane mining complex met the held for sale criteria, we recorded an impairment charge of approximately $2.3 million for the third quarter ended September 30, 2015 and we ceased depreciation of this asset group at this time. Upon the completion of the sales agreement for the Deane mining complex, we removed the assets and liabilities related to this mining complex, which resulted in a gain of $0.4 million that was record in the Asset impairment and related charges line of the consolidated statements of operations and comprehensive income. The net $1.9 million asset impairment charge/loss for the Deane mining complex is recorded on the Asset impairment and related charges line of the consolidated statements of operations and comprehensive income.

 

Cana Woodford Oil and Natural Gas Investment Sale

 

In August 2015, we completed the sale of our oil and natural gas investment of approximately 1,900 net mineral acres in the Cana Woodford region of western Oklahoma. We received a total of approximately $5.7 million in proceeds from the sale of the Cana Woodford oil and natural gas mineral rights. In the second quarter of 2015, we evaluated the appropriate held for sale accounting criteria to determine if the Cana Woodford mineral rights should be classified as held for sale. Based on this evaluation, we determined these mineral rights met the held for sale criteria at June 30, 2015 and, accordingly, these mineral rights were written down to their estimated fair value of $5.8 million. Due to the determination that the mineral rights met the held for sale criteria, we recorded an impairment charge of approximately $2.2 million for the Cana Woodford mineral rights during the second quarter of 2015. The impairment charge for the Cana Woodford mineral rights is recorded on the Asset impairment and related charges line of the consolidated statements of operations and comprehensive income.

 

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Bevins Branch Operation

 

We had a steam coal surface mine operation in eastern Kentucky (referred to as “Bevins Branch”) in our Central Appalachia segment that was idled during mid-2014 as that location’s contract with its single customer expired at that time. In May 2015, we finalized a contractual agreement with a third party to assume the Bevins Branch operation. As of December 31, 2015, we removed the assets and liabilities related to this mining complex, which resulted in a gain of $1.2 million that was record in the Asset impairment and related charges line of the consolidated statements of operations and comprehensive income.

 

Intangible Asset Impairment