Item 1. Business.

We were originally organized in Delaware on March 22, 1999, with the name Webmarketing, Inc. (“Webmarketing”). On July 7, 2004, we revived our charter and changed our name from Webmarketing to World Marketing, Inc. In December 2007, we changed our name to Royal Energy Resources, Inc.

Prior to March 2015, we pursued gold, silver, copper and rare earth metals mining concessions in Romania and mining leases in the United States. We engaged in these activities through two subsidiaries, Development Resources, Inc., a Delaware corporation, and S.C. Golden Carpathian Resources S.R.L., a Romanian subsidiary (collectively, the “Subsidiaries”). Effective January 31, 2015, we entered into a Subsidiaries Option Agreement with Jacob Roth, our chairman and chief executive officer at that time. Under the Subsidiaries Option Agreement, we conveyed all of our assets to the Subsidiaries, to the extent any assets were not already owned by the Subsidiaries. The Subsidiaries Option Agreement also granted Mr. Roth an option to acquire the Subsidiaries for 49,000 shares of Series A Preferred Stock owned by Mr. Roth. The Subsidiaries Option Agreement also granted us a put option to acquire 49,000 shares of Series A Preferred Stock owned by Mr. Roth in consideration for the Subsidiaries. Both options could be exercised at any time within 45 days after closing of the stock purchase agreement among Mr. Roth, E-Starts Money Co. and William Tuorto.

On March 6, 2015, E-Starts Money Co. (“E-Starts”) acquired an aggregate of 7,188,560 shares of common stock from two holders. At the same time, William Tuorto acquired 810,316 shares of common stock from Mr. Roth, and 51,000 shares of Mr. Roth’s Series A Preferred Stock. Mr. Tuorto controls E-Starts. As a result, Mr. Tuorto became the beneficial owner of 7,998,876 shares of common stock (representing 92.3% of the outstanding common stock at that time) and 51% of the outstanding shares of Series A Preferred Stock. In connection with these transactions: (i) Frimet Taub resigned as a director and from all positions as an officer, employee, or independent contractor of us; (ii) Mr. Tuorto was appointed to the board seat vacated by Ms. Taub; (iii) Mr. Roth resigned as chairman of the board and Mr. Tuorto was appointed chairman of the board; (iv) Mr. Roth resigned as the Chief Executive Officer and Chief Financial Officer of us, and any other position as an officer, employee or independent contractor of us, and Mr. Tuorto was appointed as the Chief Executive Officer, Interim Chief Financial Officer, Secretary and Treasurer; and (v) Mr. Roth resigned as a director of us, provided that his resignation was not effective until the close of business on the 10th day after we distributed an information statement to its shareholders in accordance with SEC Rule 14f-1.

Since acquiring control of us, Mr. Tuorto has repositioned us to focus on the acquisition of natural resources assets, including coal, oil, gas and renewable energy, seeking to acquire high quality assets at distressed pricing in today’s fragmented energy markets. To that effect, we have entered into the following initial transactions:

Acquisition of Rhino GP, LLC and Rhino Resource Partners, LLC

On January 21, 2016, we entered into a Securities Purchase Agreement (the “Purchase Agreement”) with Wexford Capital, LP, and certain of its affiliates (collectively, “Wexford”), under which we agreed to purchase, and Wexford agreed to sell, a controlling interest in the Partnership in two separate transactions. Pursuant to the Purchase Agreement, in an initial closing, we purchased 676,912 common units of the Partnership from three holders for total consideration of $3,500,000. The common units purchased by us represented approximately 40.0% of the issued and outstanding common units of the Partnership and 23.1% of the total outstanding common units and subordinated units. The subordinated units are convertible into common units on a one for one basis upon the occurrence of certain conditions.

At a second closing held on March 17, 2016, we purchased all of the membership interest of Rhino GP, LLC (“Rhino GP”), and 945,526 subordinated units of the Partnership from two holders thereof, for aggregate consideration of $1,000,000. The subordinated units purchased by us represented approximately 76.5% of the issued and outstanding subordinated units of the Partnership, and when combined with the common units already owned by us, resulted in us owning approximately 55.4% of the outstanding Units of the Partnership. Rhino GP is the general partner of the Partnership, and in that capacity controls the Partnership.

On March 21, 2016, we entered into a Securities Purchase Agreement (the “SPA”) with the Partnership, under which we purchased 6,000,000 newly issued common units of the Partnership for $1.50 per common unit, for a total investment in the Partnership of $9,000,000. Closing under the SPA occurred on March 22, 2016. We paid a cash payment of $2,000,000 and issued a promissory note in the amount of $7,000,000 to the Partnership, which was payable without interest on the following schedule: $3,000,000 on or before July 31, 2016; $2,000,000 on or before September 30, 2016; and $2,000,000 on or before December 31, 2016. On May 13, 2016 and September 30, 2016, we paid the Partnership $3.0 million and $2.0 million, respectively, for the promissory note installments that were due July 31, 2016 and September 30, 2016, respectively.  On December 30, 2016, we and the Partnership agreed to extend the maturity date of the final installment of the note to December 31, 2018, and agreed that the note may be converted, at our option, at any time prior to December 31, 2018, into unregistered shares of our common stock at a price per share equal to seventy five percent (75%) of the volume weighted average closing price for the ninety (90) trading days preceding the date of conversion, provided that the average closing price shall be no less than $3.50 per share and no more than $7.50 per share.

Yorktown Transactions

On September 30, 2016, we entered into an Equity Exchange Agreement with the Partnership, Yorktown Partners LLC (“Yorktown”), Resources Partners Holdings, LLC (“Rhino Holdings”), an entity wholly-owned by Yorktown, and Rhino GP. The Equity Exchange Agreement provided that Yorktown would cause investment partnerships it controls to contribute their shares of common stock of Armstrong Energy, Inc. (“Armstrong”) to Rhino Holdings and Rhino Holdings would contribute those shares to the Partnership in exchange for 10 million newly issued common units of the Partnership. The Agreement also contemplated that Rhino GP would issue a 50% ownership of Rhino GP to Rhino Holdings.

On December 30, 2016, we entered into an Option Agreement with the Partnership, Rhino Holdings, Yorktown, and Rhino GP. Upon execution of the Option Agreement, the Partnership received an option (the “Call Option”) from Rhino Holdings to acquire all of the shares of common stock of Armstrong Energy that are currently owned by investment partnerships managed by Yorktown (the “Armstrong Shares”), which currently represents 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 the Partnership can exercise the Call Option no earlier than January 1, 2018 and no later than December 31, 2019. In exchange for Rhino Holdings granting the Partnership the Call Option, the Partnership issued 5.0 million common units (the “Call Option Premium Units”) to Rhino Holdings upon the execution of the Option Agreement. The Option Agreement stipulates the Partnership can exercise the Call Option and purchase the Armstrong Shares 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 the Partnership (determined without considering any common units issuable upon conversion of subordinated units or Series A Preferred Units of the Partnership). The purchase of the Armstrong Shares through the exercise of the Call Option would also require us to transfer a 51% ownership interest in Rhino GP to Rhino Holdings. The Partnership’s 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 the Partnership’s revolving credit facility to permit the acquisition of Armstrong Energy. The percentage ownership of Armstrong Energy represented by the Armstrong Shares as of the date the Call Option is exercised is subject to dilution based upon the terms under which Armstrong Energy restructures its indebtedness, the terms of which have not been determined.

The Option Agreement also contains an option (the “Put Option”) granted by the Partnership to Rhino Holdings whereby Rhino Holdings has the right, but not the obligation, to cause the Partnership to purchase the Armstrong Shares 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 into an agreement with its bondholders to restructure its bonds and (ii) the termination and repayment of any outstanding balance under the Partnership’s revolving credit facility. In the event either the Partnership or Rhino GP fail to perform their obligations in the event Rhino Holdings exercises the Put Option, then Rhino Holdings and the Partnership each have the right to terminate the Option Agreement, in which event no party thereto shall have any liability to any other party under the Option Agreement, although Rhino Holdings shall be allowed to retain the Call Option Premium Units.

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 and the GP Amendment (defined below). The Partnership has entered into a non-disclosure agreement with Armstrong Energy under which it has inspection rights with regard to the books, records and operations of Armstrong Energy, and the Option Agreement provides that those rights shall continue until the Call Option or Put Option are exercised or expire. Upon the request by Rhino Holdings, the Partnership 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, Rhino GP amended its Second Amended and Restated Limited Liability Company Agreement (“GP Amendment”). Pursuant to the GP Amendment, Mr. Bryan H. Lawrence was appointed to the board of directors of Rhino GP 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 Rhino GP board of directors 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 Rhino GP’s board. Upon the exercise of the Call Option or the Put Option, the Second Amended and Restated Limited Liability Company Agreement of Rhino GP, 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 Rhino GP unless agreed otherwise.

Transactions with Weston Energy, LLC

First Weston Loan

On September 30, 2016, we entered into a Secured Promissory Note and a Pledge and Security Agreement with Weston Energy, LLC (“Weston”), under which we borrowed $2,000,000 from Weston (the “Loan”). Weston is an affiliate of Yorktown. The Loan bears interest at 8% per annum. All principal and accrued interest was originally due and payable on December 31, 2016. The Loan is payable, at our option of the Company, either in cash or in common units of the Partnership (“Rhino Units”). In the event we elect to pay the Loan in Rhino Units, the number of Rhino Units that will be conveyed to satisfy the Loan will be equal to Loan balance divided by 80% of the average of the high and low price of the Partnership’s common units for the twenty trading days prior to the date of payment. The proceeds of the Loan were used to make an installment payment of $2,000,000 due to the Partnership on September 30, 2016.

On December 30, 2016, Weston contributed the Loan to the Partnership in payment for 200,000 shares of Series A Preferred Stock issued by the Partnership at $10 per unit. We simultaneously entered into a letter agreement with the Partnership which extended the maturity date of the Loan to December 31, 2018, and provided that the Loan may be converted, at our option, at any time prior to December 31, 2018, into unregistered shares of our common stock at a price per share equal to seventy five percent (75%) of the volume weighted average closing price for the ninety (90) trading days preceding the date of conversion, provided that the such average closing price shall be no less than $3.50 per share and no more than $7.50 per share.

Second Weston Loan

On December 30, 2016, we entered into a second Secured Promissory Note and a Pledge and Security Agreement with Weston, under which we borrowed $2.0 million from Weston (the “Second Loan”). The Second Loan bears interest at 8% per annum. All principal and accrued interest was due and payable on January 15, 2017. The Loan was payable, at the option of Royal, either in cash or Rhino Units. In the event Royal elected to pay the Second Loan in Rhino Units, the number of Rhino Units that would be conveyed to satisfy the Second Loan would be equal to Second Loan balance divided by 80% of the average of the high and low price of the Partnership’s common units for the twenty trading days prior to the date of payment. The proceeds of the Second Loan were used to make an investment of $2.0 million in Series A Preferred Units of the Partnership on December 30, 2016.

On January 27, 2017, we sold the 2.0 million in Series A Preferred Units for their purchase price, and used the proceeds to repay the Second Loan in full.

About Rhino

History

The Partnership’s predecessor was formed in April 2003 by Wexford Capital. The Partnership was formed in April 2010 to own and control the coal properties and related assets owned by Rhino Energy LLC. On October 5, 2010, the Partnership completed its IPO. Its common units were originally listed on the New York Stock Exchange under the symbol “RNO”. In connection with the IPO, Wexford contributed their membership interests in Rhino Energy LLC to the Partnership, and in exchange the Partnership issued subordinated units and common units to Wexford and issued incentive distribution rights to Rhino GP, its general partner.

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

The Partnership is managed by the board of directors and executive officers of Rhino GP. Its operations are conducted through, and its operating assets are owned by its wholly owned subsidiary, Rhino Energy LLC, and its subsidiaries.

Current Operations

The Partnership is a diversified energy limited partnership formed in Delaware that is focused on coal and energy related assets and activities, including energy infrastructure investments. The Partnership produces, processes and sells high quality coal of various steam and metallurgical grades from multiple coal producing basins in the United States. The Partnership markets its steam coal primarily to electric utility companies as fuel for their steam powered generators. Customers for its metallurgical coal are primarily steel and coke producers who use its coal to produce coke, which is used as a raw material in the steel manufacturing process. Its business includes investments in joint ventures to provide for the transportation of hydrocarbons and drilling support services in the Utica Shale region. The Partnership has 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.

The Partnership has 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, it 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, it controlled an estimated 196.5 million tons of non-reserve coal deposits. Both its 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 its Elk Horn coal leasing business in August 2016. As part of the recent audits of its 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.

The Partnership operates underground and surface mines located in Kentucky, Ohio, West Virginia and Utah. The number of mines that it operates 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, it temporarily idled a majority of its Central Appalachia operations due to ongoing weak coal market conditions for met and steam coal produced from this region. The Partnership resumed mining operations at all of its Central Appalachia operations in 2016 to fulfill customer contracts that it secured for 2016 and 2017.

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

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

The Partnership’s common units currently trade on the OTCQB Marketplace under the symbol “RHNO.” The Partnership’s common units previously traded on the NYSE until December 17, 2015, when the NYSE suspended trading after the Partnership failed to maintain an average global market capitalization over a consecutive 30 trading-day period of at least $15 million for its common units. The Partnership is exploring the possibility of listing its common units on the NASDAQ Stock Market (“NASDAQ”), pending its capability to meet the NASDAQ initial listing standards.

Current Liquidity and Outlook of Rhino

As of December 31, 2016, the Partnership’s available liquidity was $13.0 million, including cash on hand of $0.1 million and $12.9 million available under its amended and restated credit agreement. On May 13, 2016, the Partnership entered into a fifth amendment (the “Fifth Amendment”) of its 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 maintained the amount available for letters of credit at $30 million. As of December 31, 2016, the Partnership met the requirements to extend the maturity date of the credit facility to December 31, 2017. In December 2016, the Partnership entered into a seventh amendment of its amended and restated credit agreement (the “Seventh Amendment”). The Seventh Amendment immediately reduced the revolving credit commitments by $11.0 million to a maximum of $55 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 its amended and restated credit agreement, please read “Part 1, Item 1-- Recent Developments-Amendments to Amended and Restated Credit Agreement.”

Since the Partnership’s credit facility has an expiration date of December 2017, we determined that its credit facility debt liability of $10.0 million at December 31, 2016 should be classified as a current liability on our consolidated balance sheet. The classification of the Partnership’s 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. The Partnership is also considering alternative financing options that could result in a new long-term credit facility. However, the Partnership may be unable to complete such a transaction on terms acceptable to us or at all. If the Partnership is unable to extend the expiration date of the Partnership’s amended and restated credit facility, it will have to secure alternative financing to replace the credit facility by the expiration date of December 31, 2017 in order to continue its business operations. If the Partnership is unable to extend the expiration date of the Partnership’s amended and restated credit facility or secure a replacement facility, it will lose a primary source of liquidity, and it may not be able to generate adequate cash flow from operations to fund its business, including amounts that may become due under its 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, the Partnership may not be able to continue to give the required representations or meet all of the covenants and restrictions included in its credit facility. If the Partnership violates any of the covenants or restrictions in its amended and restated credit agreement, including the maximum leverage ratio, some or all of its indebtedness may become immediately due and payable, and its lenders’ commitment to make further loans to it may terminate. If the Partnership is unable to give a required representation or it violates a covenant or restriction, then it will need a waiver from its lenders in order to continue to borrow under its amended and restated credit agreement. Although we believe the Partnership’s lenders loans are well secured under the terms of its 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 the Partnership to further curtail our operations and reduce its spending and to alter its business plan. The Partnership may also be required to consider other options, such as selling additional assets or merger opportunities, and depending on the urgency of its liquidity constraints, it may be required to pursue such an option at an inopportune time. If the Partnership is not able to fund its liquidity requirements for the next twelve months, it may not be able to continue as a going concern. For more information about our liquidity and the Partnership’s credit facility, please read “Part II, Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations —Liquidity and Capital Resources.”

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

Recent Developments - Rhino

Fourth Amended and Restated Partnership Agreement of Limited Partnership

On December 30, 2016, Rhino GP amended the Partnership’s 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 its 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 its partnership agreement as (i) the total revenue of its Central Appalachia business segment, minus (ii) the cost of operations (exclusive of depreciation, depletion and amortization) for its 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 the Partnership from its Central Appalachia business segment. If the Partnership fails 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 it will not be permitted to pay any distributions on its partnership interests that rank junior to the Series A preferred units, including its 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 the Partnership is 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 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 its Central Appalachia business segment, subject to certain exceptions.

Series A Preferred Unit Purchase Agreement

On December 30, 2016, the Partnership entered into a Series A Preferred Unit Purchase Agreement (the “Preferred Unit Agreement”) with 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 the Partnership 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 the Partnership’s 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 the Partnership, and Weston assigned to the Partnership a $2.0 million note receivable from Royal originally dated September 30, 2016 (the “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, the Partnership will cause CAM Mining, LLC, one of its 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 the Partnership’s common units following their conversion from Series A preferred units, the Partnership 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, we sold 100,000 of our Series A preferred units to Weston and the other 100,000 Series A preferred units to another third party.

Elk Horn Coal Leasing Disposition

In August 2016, the Partnership entered into an agreement to sell its Elk Horn coal leasing company to a third party for total cash consideration of $12.0 million. The Partnership 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.

Amended and Restated Credit Agreement Amendments

On March 17, 2016, the Partnership’s Operating Company, as borrower, and the Partnership and certain of its subsidiaries, as guarantors, entered into a fourth amendment (the “Fourth Amendment”) of its 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 its general partner.

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

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

In December, 2016, the Partnership entered into a seventh amendment of its amended and restated credit agreement (the “Seventh Amendment”). 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 its credit agreement. (See “—Liquidity and Capital Resources—Amended and Restated Credit Agreement” for further details on the debt amendments).

Distribution Suspension

Pursuant to its partnership agreement, the Partnership’s common units accrue arrearages every quarter when the distribution level is below the minimum level of $4.45 per unit. For each of the quarters ended September 30, 2014, December 31, 2014 and March 31, 2015, the Partnership announced cash distributions per common unit at levels lower than the minimum quarterly distribution. Beginning with the quarter ended June 30, 2015 and continuing through the quarter ended December 31, 2016, the Partnership has suspended the cash distribution on its common units. The Partnership has not paid any distribution on its 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 its cash flow, as well as covenants in its loan agreement that prevent it from making distributions on its units. The inability of the Partnership to make distributions on its common units could impact Royal’s cash flow while it lacks other revenue generating operations.

Coal Operations

Mining and Leasing Operations

As of December 31, 2016, the Partnership operated two mining complexes located in Central Appalachia (Tug River and Rob Fork). In the third quarter of 2015, the Partnership temporarily idled a majority of its Central Appalachia operations due to ongoing weak coal market conditions for met and steam coal produced from this region. The Partnership resumed mining operations at all of its Central Appalachia operations in 2016 to fulfill customer contracts that it secured for 2016 and 2017.

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

The Partnership defines a mining complex as a central location for processing raw coal and loading coal into railroad cars 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 its active surface and underground mines. All of the preparation plants are modern plants that have both coarse and fine coal cleaning circuits.

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

The Partnership’s surface mines include area mining and contour mining. These operations use truck and wheel loader equipment fleets along with large production tractors and shovels. The Partnership’s 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. The Partnership currently owns most of the equipment utilized in its mining operations. The Partnership employs preventive maintenance and rebuild programs to ensure that its 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 the Partnership’s mining complexes and production by region as of December 31, 2016.

Central Appalachia. For the year ended December 31, 2016, the Partnership 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 its 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. The Partnership’s Tug River mining complex is located in Kentucky and West Virginia bordering the Tug River. This complex produces coal from two 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.

Rob Fork Mining Complex. The Partnership’s Rob Fork mining complex is located in eastern Kentucky and produces coal from one surface mine and one 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, the Partnership operated two mining complexes located in Northern Appalachia consisting of one underground mine and two surface mines.

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 its Nelms preparation plant located on the Ohio Central Railroad and the Wheeling & Lake Erie Railroad and then shipped by train or truck to its 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. The Partnership currently operates one surface mine at its Sands Hill mining complex, located near Hamden, Ohio, and it 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. Coal mining at its Sands Hill complex will cease during the first quarter of 2017 as market conditions for coal from this complex have continued to be weak. The Partnership will continue its limestone aggregate business at the Sands Hill complex for the next twelve to eighteen months as it has 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.

Western Bituminous Region. The Partnership operates one mining complex in the Western Bituminous region that produces coal from an underground mine located in Emery and Carbon Counties, Utah. The Partnership 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. The Partnership’s Castle Valley mining complex includes one underground mine located in Emery and Carbon Counties, Utah and includes coal reserves and non-reserve coal deposits, underground mining equipment and infrastructure, an overland belt conveyor system, a loading facility and support facilities. The Partnership 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, the Partnership 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 it constructed a new underground mining complex. The coal leases and property are contiguous to the Green River. 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.

Pennyrile Mining Complex. In mid-2014, it completed the initial construction of a new underground mining operation on the purchased property, referred to as its 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 it produced approximately 1.3 million tons for the year ended December 31, 2016. The Partnership believes the possibility exists to expand production up to 2.0 million tons per year with further development of the mine at the Pennyrile complex. The Partnership has long-term sales contracts with local electric utility customers and it has other potential customers that it believes could lead to additional long-term sales agreements if it can successfully expand its production capacity at this operation.

Other Non-Mining Operations

In addition to its mining operations, the Partnership operates several subsidiaries which provide auxiliary services for its coal mining operations. Rhino Trucking provides its southeastern Ohio coal operations with reliable transportation to its 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, the Partnership plans and monitors each phase of its mining projects as well as the post-mining reclamation efforts. The Partnership also performs the majority of its drilling and blasting activities at its surface mines in-house rather than contracting to a third party.

Other Natural Resource Assets - Rhino

Oil and Natural Gas

In addition to its coal operations, the Partnership has invested in oil and natural gas assets and operations.

In September 2014, the Partnership 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. The Partnership accounts for the investment in this joint venture and results of operations under the equity method. The Partnership recorded its proportionate portion of the operating (losses)/gains for this investment during the nine months ended December 31, 2016 of approximately ($0.2   ) million.

In November 2014, the Partnership contributed its 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 its investment interest in the Muskie entity for an investment interest in Mammoth. Thus, the Partnership determined that the non-cash exchange of its ownership interest in Muskie did not result in any gain or loss. In October 2016, the Partnership contributed its 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 the Partnership sold 1,953 shares during the initial public offering of Mammoth Inc. and received proceeds of approximately $27,000. The Partnership’s 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, the Partnership recorded a fair market value adjustment of $1.6 million for the available-for-sale investment, which was recorded in other comprehensive income. The Partnership has included its investment in Mammoth and its prior investment in Muskie in its Other category for segment reporting purposes.  

Limestone

Incidental to its coal mining process, the Partnership mines limestone from reserves located at its 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. The Partnership believes that its production of limestone will provide us with an additional source of revenues at low incremental capital cost for the next twelve to eighteen months.

Coal Customers - Rhino

General

The Partnership’s primary customers for its steam coal are electric utilities, and the metallurgical coal the Partnership produces is sold primarily to domestic and international steel producers. For the year ended December 31, 2016, approximately 90.0% of its 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 its coal sales tons that the Partnership produced were sold to electric utilities. The majority of its electric utility customers purchase coal for terms of one to three years, but it also supplies coal on a spot basis for some of its customers. For the year ended December 31, 2016, the Partnership derived approximately 87.4% of its total coal revenues from sales to its ten largest customers, with affiliates of its top three customers accounting for approximately 48.5% of its coal revenues for that period: PPL Corporation (26.2%); PacificCorp Energy (12.2%); and Big Rivers (10.1%).

Coal Supply Contracts

For the year ended December 31, 2016, approximately 90% of the Partnership’s aggregate coal tons sold were sold through supply contracts. The Partnership expects to continue selling a significant portion of its coal under supply contracts. As of December 31, 2016, the Partnership had commitments under supply contracts to deliver annually scheduled base quantities as follows:

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 the Partnership’s coal supply contracts contain provisions requiring it 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 its contracts specify approved locations from which coal may be sourced. Some of its 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 it or unanticipated plant outages that may affect the buyers.

The terms of its 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

The Partnership ships coal to its customers by rail, truck or barge. The majority of its 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, the Partnership uses its own trucking operations to transport coal to its customers where rail is not available. The Partnership uses third-party trucking to transport coal to its customers in Utah. For its Pennyrile complex in western Kentucky, coal is transported to its customers via barge from its river loadout on the Green River located on its Pennyrile mining complex. In addition, coal from certain of its 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.

The Partnership believes that it has good relationships with rail carriers and truck companies due, in part, to its modern coal-loading facilities at its loadouts and the working relationships and experience of its transportation and distribution employees.

Suppliers - Rhino

Principal supplies used in the Partnership’s business include diesel fuel, explosives, maintenance and repair parts and services, roof control and support items, tires, conveyance structures, ventilation supplies and lubricants. The Partnership uses third-party suppliers for a significant portion of its equipment rebuilds and repairs, drilling services and construction.

The Partnership has 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. The Partnership is not dependent on any one supplier in any region. The Partnership promotes competition between suppliers and seek to develop relationships with those suppliers whose focus is on lowering its costs. The Partnership seeks suppliers who identify and concentrate on implementing continuous improvement opportunities within their area of expertise.

Competition - Rhino

The coal industry is highly competitive. There are numerous large and small producers in all coal producing regions of the United States and the Partnership competes with many of these producers. The Partnership’s 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 the Partnership competes are coal price, coal quality and characteristics, transportation costs and the reliability of supply. Demand for coal and the prices that the Partnership will be able to obtain for its 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 its 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

The Partnership’s current operations are, and future coal mining operations that we acquire will be, subject to regulation by federal, state and local authorities on matters such as:

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.

The Partnership is 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.

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. The Partnership has 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 the Partnership 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.

The Partnership has 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. The Partnership has 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 the Partnership’s 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. The rulemaking record for this proposed rule was closed on December 15, 2016, but on January 9, 2017, MSHA published a notice reopening the record and extending the comment period for this proposed rule for 30 days. 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.

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), the Partnership received such orders from government agencies and has experienced accidents within its 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 the Partnership to suspend operations on a mine-wide level or otherwise entail material financial or operational consequences for it. Any suspension of operations at any one of the Partnership’s locations that may occur in the future may have material financial or operational consequences for us.

It is the Partnership’s practice to contest notices of violations in cases in which it believes it has 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. The Partnership exercises substantial efforts toward achieving compliance at its mines. For example, it has further increased its focus with regard to health and safety at all of its 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 the Partnership’s 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 the Partnership monitors 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

The Partnership is 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. Its costs will vary based on the number of accidents that occur at our mines and other facilities, and its costs of addressing these claims. The Partnership is insured under the Ohio State Workers Compensation Program for our operations in Ohio. Its remaining operations, including Central Appalachia and the Western Bituminous region, are insured through Rockwood Casualty Insurance Company.

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, the Partnership reclaims and restores 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 the Partnership is 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, the Partnership 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 the Partnership would be (and it is 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 the Partnership’s operations.

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. The Partnership’s failure to maintain, or inability to acquire, surety bonds that are required by state and federal laws would have a material adverse effect on its ability to produce coal, which could affect its profitability and cash flow.

As of December 31, 2016, the Partnership had approximately $48.9 million in surety bonds outstanding to secure the performance of its reclamation obligations. It 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 the Partnership’s 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 the Partnership’s operations, directly or indirectly, through impacts to coal-fired utilities and other manufacturing plants, include, but are not limited to, the following:

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 the Partnership’s 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 the Partnership’s mining operations could become subject to further regulation pursuant to existing laws such as the CAA. In that event, the Partnership may be required to install additional emissions control equipment or take other steps to lower emissions associated with its operations, thereby reducing its revenues and adversely affecting its operations.

Carbon Dioxide Emissions

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

Future regulation of GHG in the United States could occur pursuant to future U.S. treaty commitments, or new domestic legislation that may impose a carbon emissions tax or establish a cap-and-trade program or regulation by the EPA. 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.

In August 2015, the EPA issued its final Clean Power Plan (the “CPP”) rules that establish carbon pollution standards for power plants, called CO ₂ 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 EPA has given states the option to develop compliance plans for annual rate-based reductions (pounds per megawatt hour) or mass-based tonnage limits for CO ₂ . The state plans were to be due in September 2016, subject to potential extensions of up to two years for final plan submission. 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 before the United States Court of Appeals for the District of Columbia (“Circuit Court”) even issued a decision. By its terms, this stay will remain in effect throughout the pendency of the appeals process including at the Circuit Court and the Supreme Court through any certiorari petition that may be granted. 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 CO ₂ emissions from existing power plants and will not affect EPA’s standards for new power plants. It is not yet clear how either the Circuit Court or the Supreme Court 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 the Partnership mines and sells, thereby reducing its revenues and materially and adversely affecting its 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 (“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 the Partnership’s current and prospective customers, they may reduce the demand for coal-fired power, and may affect long-term demand for its 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 carbon capture and storage technology have been proposed or enacted. On February 3, 2010, President Obama sent a memorandum to the heads of fourteen Executive Departments and Federal Agencies establishing an Interagency Task Force on Carbon Capture and Storage (“CCS”). The goal was to develop a comprehensive and coordinated Federal strategy to speed the commercial development and deployment of clean coal technologies. On August 12, 2010, the Task Force delivered a series of recommendations on overcoming the barriers to the widespread, cost-effective deployment of CCS within ten years. The report concludes that CCS can play an important role in domestic GHG emissions reductions while preserving the option of using abundant domestic fossil energy resources. 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 CO ₂ 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.

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 the Partnership’s 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. 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. The Partnership’s 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.” On January 14, 2011, the EPA exercised its Section 404(c) authority to withdraw or restrict the use of a previously issued permit for the Spruce No. 1 Surface Mine in West Virginia, which is one of the largest surface mining operations ever authorized in Appalachia. This action was the first time that such power was exercised with regard to a previously permitted coal mining project. A challenge to the EPA’s exercise of this authority was made in the federal District Court in the District of Columbia and on March 23, 2012, the Court ruled that the EPA lacked the statutory authority to invalidate an already issued Section 404 permit retroactively. This decision was appealed and reversed by the D.C. Circuit Court of Appeals in April 2013, finding that EPA has the authority to issue a retroactive veto, but remanding for consideration of whether that decision was arbitrary and capricious. The mining company has also petitioned the U.S. Supreme Court for certiorari to overturn the ruling. The Supreme Court denied certiorari in March 2014. Any future use of the EPA’s Section 404 “veto” power could create uncertainty with regard to the Partnership’s continued use of their current permits, as well as impose additional time and cost burdens on future operations, potentially adversely affecting its 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 the Partnership’s 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. The Partnership’s 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 its applications may not be granted or, alternatively, the Corps may require material changes to its proposed operations before it grants permits. While the Partnership will continue to pursue the issuance of these permits in the ordinary course of its operations, to the extent that the permitting process creates significant delay or limits its ability to pursue certain reserves beyond its current five year plan, its revenues may be negatively affected.

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 its coal mines could limit its ability to obtain NPDES permits, require more costly water treatment, and adversely affect its coal production.

In addition, in May 2014, EPA issued a new final rule pursuant to Section 316(b) of the CWA that affects the cooling water intake structures at power plants in order to reduce fish impingement and entrainment. The rule is expected to affect over 500 power plants. These requirements could increase its customers’ costs and cause them to reduce their demand for coal, which may materially impact its results or operations.

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 the Partnership’s 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 the Partnership’s 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 the Partnership’s business, financial condition or results of operations, and could potentially increase its 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 its customers under RCRA or other federal or state laws and potentially reduce the demand for coal.

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 the Partnership 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 the Partnership’s 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 its ability to mine coal from its properties in accordance with current mining plans.

Use of Explosives

The Partnership uses explosives in connection with its 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 its use of explosives in connection with blasting operations may subject the Partnership 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 its 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 its blasting operations.

Other Environmental and Mine Safety Laws

The Partnership is also 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 the Partnership’s business, financial condition or results of operations.

Employees

We 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 the Partnership has good relations with these employees and since its inception it has had no history of work stoppages or union organizing campaigns.

Available Information

Our internet address is http://www.royalenergy.us , 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. 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.

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.