UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

WASHINGTON, D.C. 20549

Form 10-K

[X]

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

For the fiscal year ended December 31, ~~2018 or~~2019

[ ]

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

For the transition period from to

Commission file number: 001-34892

Rhino Resource Partners LP

(Exact name of registrant as specified in its charter)

Delaware		27-2377517
(State or other jurisdiction of incorporation or organization)		(I.R.S. Employer Identification No.)

424 Lewis Hargett Circle, Suite 250 Lexington, KY (Address of principal executive offices)		40503 (Zip Code)

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

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

None

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

Common Units representing Limited Partner Interests

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

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

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

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

Title of each class		Trading Symbol(s)		Name of each Exchange on which registered
n/a		n/a		n/a

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

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

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

Large accelerated filer [ ]

Accelerated filer [ ]

Non-accelerated filer [ ]
(Do not check if a
smaller reporting company)

Smaller reporting company [X]

Emerging growth company [ ]

If an emerging growth company, indicate by check mark if the registrant has elected not to use the extended transition period for complying with any new or revised financial accounting standards provided pursuant to Section 13(a) of the Securities Act. [ ]

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

As of June 2928, ~~2018~~2019, the last business day of the registrant’s most recently completed second fiscal quarter, the aggregate market value of the registrant’s equity held by non-affiliates of the registrant was approximately $2.1.3 million based on the price at which the registrant’s common units were last sold on the OTCQB Marketplace on such date. As of March 1520, ~~2019,~~ 2020, the registrant had 13,~~098~~078,~~353~~668 common units, 1,143,~~686~~171 subordinated units and 1,500,000 Series A preferred units outstanding.

DOCUMENTS INCORPORATED BY REFERENCE

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

TABLE OF CONTENTS

	PART I
Item 1.	Business	1
Item 1A.	Risk Factors	2322
Item 1B.	Unresolved Staff Comments	52
Item 2.	Properties	52
Item 3.	Legal Proceedings	5457
Item 4.	Mine Safety Disclosure	5458
PART II
Item 5.	Market for Registrant’s Common Equity, Related Unitholder Matters and Issuer Purchases of Equity Securities	5558
Item 6.	Selected Financial Data	5861
Item 7.	Management’s Discussion and Analysis of Financial Condition and Results of Operations	5861
Item 7A.	Quantitative and Qualitative Disclosures About Market Risk	8083
Item 8.	Financial Statements and Supplementary Data	8083
Item 9.	Changes in and Disagreements with Accountants on Accounting and Financial Disclosure	8083
Item 9A.	Controls and Procedures	8184
Item 9B.	Other Information	8184
PART III
Item 10.	Directors, Executive Officers and Corporate Governance	8285
Item 11.	Executive Compensation	8588
Item 12.	Security Ownership of Certain Beneficial Owners and Management and Related Unitholder Matters	9092
Item 13.	Certain Relationships and Related Transactions, and Director Independence	9194
Item 14.	Principal Accounting Fees and Services	9497
PART IV
Item 15.	Exhibits, Financial Statement Schedules	9598
Item 16.	Form 10K Summary	9598
FINANCIAL STATEMENTS
	Index to Financial Statements	F-1

GLOSSARY OF KEY TERMS

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

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

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

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

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

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

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

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

GAAP: Generally accepted accounting principles in the United States.

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

~~iii~~ii

CAUTIONARY STATEMENT REGARDING FORWARD-LOOKING INFORMATION

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

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

● our ability to acquire or failure to maintain, obtain or renew surety bonds used to secure obligations to reclaim mined property; ● our dependence on a few customers and our ability to find and retain customers under favorable supply contracts; ● changes in consumption patterns by utilities away from the use of coal, such as changes resulting from low natural gas prices; ● changes in governmental regulation of the electric utility industry; ● defects in title in properties that we own or losses of any of our leasehold interests; ● our ability to retain and attract senior management and other key personnel; ● material inaccuracy of assumptions underlying reclamation and mine closure obligations; and ● weakness in global economic conditions.iii

	●	material inaccuracies in our estimates of coal reserves and non-reserve coal deposits;

	●	existing and future laws and regulations regulating the emission of sulfur dioxide and other compounds, which could affect coal consumers and reduce demand for coal;

	●	federal and state laws restricting the emissions of greenhouse gases;
	●	our ability to acquire or failure to maintain, obtain or renew surety bonds used to secure obligations to reclaim mined property;

	●	our dependence on a few customers and our ability to find and retain customers under favorable supply contracts;

	●	changes in consumption patterns by utilities away from the use of coal, such as changes resulting from low natural gas prices;

	●	changes in governmental regulation of the electric utility industry;

	●	defects in title in properties that we own or losses of any of our leasehold interests;

	●	our ability to retain and attract senior management and other key personnel;

	●	material inaccuracy of assumptions underlying reclamation and mine closure obligations; and

	●	weakness in global economic conditions.

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

PART I

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

Item 1. Business.

We are a diversified coal producing limited partnership formed in Delaware that is focused on coal and energy related assets and activities. We produce, process and sell high quality coal of various steam and metallurgical grades from multiple coal producing basins in the United States. We market our steam coal primarily to electric utility companies as fuel for their steam powered generators. Customers for our metallurgical coal are primarily steel and coke producers who use our coal to produce coke, which is used as a raw material in the steel manufacturing process.

We have a geographically diverse asset base with coal reserves located in Central Appalachia, Northern Appalachia, the Illinois Basin and the Western Bituminous region. As of December 31, ~~2018~~2019, we controlled an estimated ~~268~~277.56 million tons of proven and probable coal reserves, consisting of an estimated ~~214~~171.01 million tons of steam coal and an estimated 54106.5 million tons of metallurgical coal. ~~Proven and probable coal reserves increased approximately 15.8 million tons from 2017 to 2018 primarily as the result of the revised economic feasibility of our non-reserve coal deposits.~~ In addition, as of December 31, ~~2018~~2019, we controlled an estimated ~~164~~ 190.17 million tons of non-reserve coal deposits~~, which decreased primarily due to the reclassification of non-reserve coal deposits to proven and probable reserves~~. Periodically, we retain outside experts to independently verify our coal reserve and our non-reserve coal deposit estimates. The most recent audit by an independent engineering firm of our coal reserve and non-reserve coal deposit estimates was completed by Marshall Miller & Associates, Inc. as of December 31, ~~2018~~2019, and covered a majority of the coal reserves and non-reserve coal deposits that we controlled as of such date. We intend to continue to periodically retain outside experts to assist management with the verification of our estimates of our coal reserves and non-reserve coal deposits going forward.

We operate underground and surface mines located in Kentucky, Ohio, Virginia, West Virginia and Utah. The number of mines that we operate will vary from time to time depending on a number of factors, including the existing demand for and price of coal, depletion of economically recoverable reserves and availability of experienced labor.

For the year ended December 31, ~~2018~~2019, we produced approximately 43.42 million tons of coal from continuing operations and sold approximately 43.60 million tons of coal from continuing operations.

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

Current Liquidity and Outlook

As of December 31, ~~2018~~2019, our available liquidity was $60.21 million. We also have a delayed draw term loan commitment in the amount of $4025 million contingent upon the satisfaction of certain conditions precedent specified in the financing agreement discussed below.

On December 27, 2017, we entered into a ~~Financing~~financing ~~Agreement~~agreement (“Financing Agreement”) with Cortland Capital Market Services LLC, as Collateral Agent and Administrative agent, CB Agent Services LLC, as Origination Agent and the parties identified as Lenders therein (the “Lenders”), which provides us with a multi-draw loan in the original aggregate principal amount of $80 million. The total principal amount is divided into a $40 million commitment, the conditions for which were satisfied at the execution of the Financing Agreement and ana ~~additional~~ $3540 million additional commitment that is was contingent upon the satisfaction of certain conditions precedent specified in the Financing Agreement. As of December 31, 2019, we had utilized $15 million of the $40 million additional commitment, which results in $25 million of the additional commitment remaining. We used approximately $17.3 million of the initial Financing Agreement net proceeds ~~thereof~~ to repay all amounts outstanding and terminate the ~~Amended~~amended and ~~Restated~~restated ~~Credit~~credit ~~Agreement with~~agreement with PNC Bank, National Association, as Administrative Agent. The Financing Agreement ~~terminates~~initially onhad ~~December~~a termination date of December 27, 2020., ~~For~~which ~~more information~~was ~~about~~amended ~~our~~to ~~new~~December ~~Financing Agreement~~27, ~~please~~2022 ~~read~~per “—the ~~Recent~~fifth ~~Developments—~~amendment to the Financing Agreement discussed further below.”

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

Recent Developments

Financing Agreement

On December 27, 2017, we entered into a Financing Agreement with Cortland Capital Market Services LLC, as Collateral Agent and Administrative agent, CB Agent Services LLC, as Origination Agent and the parties identified as Lenders therein (the “Lenders”), pursuant to which Lenders agreed to provide us with a multi-draw term loan in the aggregate principal amount of $80 million, subject to the terms and conditions set forth in the Financing Agreement. The total principal amount is divided into a $40 million commitment, the conditions for which were satisfied at the execution of the Financing Agreement (the “Effective Date Term Loan Commitment”) and an additional $35 million commitment that is contingent upon the satisfaction of certain conditions precedent specified in the Financing Agreement (“Delayed Draw Term Loan Commitment”). Loans made pursuant to the Financing Agreement will be secured by substantially all of our assets. The Financing Agreement terminates on December 27, 2020. For more information about our Financing Agreement, please read “Part II, Item 7, Management’s Discussion and Analysis of Financial Condition and Results of Operations—Liquidity and Capital Resources—Financing Agreement.”

OnBeginning in the later ~~April~~part ~~17,~~of ~~2018~~the third quarter of 2019, we ~~amended~~have ~~the~~experienced ~~Financing~~significantly ~~Agreement~~weaker tomarket ~~allow~~demand ~~for~~and ~~certain~~have ~~activities~~seen ~~including~~prices amove ~~sale~~lower ~~leaseback~~for the qualities of ~~certain~~met ~~pieces of~~and ~~equipment,~~steam ~~the~~coal ~~due~~we ~~date~~produce. ~~for~~This downward price trend has been exacerbated by the ~~lease~~recent ~~consents~~coronavirus ~~was~~pandemic. If ~~extended~~we continue to ~~June~~experience ~~30,~~weak ~~2018~~demand and ~~confirmation~~prices ofcontinue ~~the~~to ~~distribution~~lower for our met and steam coal, we may not be able to ~~holders~~continue ofto give the ~~Series~~required Arepresentations ~~preferred~~or ~~units~~meet all of $6the covenants and restrictions included in our Financing Agreement.0 ~~million~~If ~~(accrued~~we violate any of the covenants or restrictions in our ~~audited~~Financing ~~consolidated~~Agreement, ~~financial~~including ~~statements~~the atfixed-charge ~~December~~coverage 31ratio, ~~2017).~~some or all ~~Additionally~~of our indebtedness may become immediately due and payable, and our Lenders may not be willing to make any loans under the ~~amendments~~additional commitment ~~provided~~available ~~that~~under our Financing Agreement. If we ~~could~~are ~~sell~~unable ~~additional~~to ~~shares~~give ofa ~~Mammoth~~required ~~Energy~~representation ~~Services~~or we violate a covenant or restriction, ~~Inc.~~then ~~(NASDAQ:~~we ~~TUSK)~~will ~~(“Mammoth~~need a waiver from our Lenders under our Financing Agreement, or they may declare an event of ~~Inc.”)~~default and, ~~retain~~after ~~50%~~applicable ofspecified cure periods, all amounts outstanding under the ~~proceeds~~Financing ~~with~~Agreement would become immediately due and payable. Although we believe our Lenders are well secured under the ~~other~~terms ~~50%~~of ~~used~~our Financing Agreement, there is no assurance that the Lenders would agree to any such waiver. Failure to obtain financing or to generate sufficient cash flow from operations could cause us to further curtail our operations and reduce ~~debt~~spending and alter our business plan. We ~~reduced~~may ~~the~~also ~~debt~~be byrequired to ~~$3.4~~consider ~~million~~other ~~with~~options ~~proceeds~~are currently considering alternatives to address our liquidity and balance sheet issues, such ~~from~~as selling additional assets or seeking merger opportunities, and depending on the ~~sale~~urgency of ~~Mammoth~~our ~~Inc.~~liquidity ~~stock~~constraints, inwe ~~the~~may ~~second~~be ~~quarter~~required ofto ~~2018~~pursue such an option at an inopportune time.

OnAs ~~July~~of 27December 31, ~~2018~~2019, we ~~entered~~were ~~into~~unable ato ~~consent~~demonstrate ~~with~~that ~~our~~we ~~Lenders~~have ~~related~~sufficient liquidity to ~~the~~operate ~~Financing~~our ~~Agreement.~~business ~~The~~over ~~consent included~~ the ~~lenders~~next twelve ~~agreement~~months tofrom ~~make~~the adate $5of ~~million~~filing ~~loan~~our ~~from~~Annual ~~the~~Report ~~Delayed~~on ~~Draw~~Form ~~Term~~10-K ~~Loan~~and ~~Commitment,~~thus ~~which~~substantial ~~was~~doubt ~~repaid~~is inraised ~~full~~about onour ~~October~~ability ~~26,~~to ~~2018 pursuant~~continue toas ~~the~~a ~~terms~~going ofconcern. ~~the~~Accordingly, ~~consent.~~our ~~The~~independent ~~consent~~registered ~~also~~public accounting firm has included aan ~~waiver~~emphasis ofparagraph ~~the~~with ~~requirements~~respect to ~~relating~~our ability to ~~the~~continue ~~use~~as ofa ~~proceeds~~going ofconcern ~~any~~in ~~sale of~~its report on our consolidated financial statements for the ~~shares~~year ofended ~~Mammoth~~December 31, ~~Inc~~2019. ~~set~~The ~~forth~~presence inof the ~~consent~~going toconcern ~~the~~emphasis ~~Financing~~paragraph ~~Agreement,~~in ~~dated~~our asauditors’ ofreport ~~April~~may ~~17,~~have ~~2018~~an ~~and~~adverse ~~also~~impact ~~waived~~on our ~~any~~relationship ~~Event~~with ofthird ~~Default~~parties ~~that~~with ~~arose~~whom orwe ~~would~~do ~~otherwise~~business, ~~arise~~including ~~under~~our ~~the~~customers, ~~Financing~~vendors, ~~Agreement~~lenders ~~for~~and ~~failing~~employees, making it difficult to ~~comply~~raise ~~with~~additional financing to the ~~Fixed~~extent ~~Charge Coverage~~needed ~~Ratio~~to ~~for~~conduct ~~the~~normal ~~six~~operations. ~~months~~As ~~ended~~a ~~June~~result, 30our business, ~~2018~~results of operations, financial condition and prospects could be materially adversely affected.

OnWe ~~November~~continue 8,to ~~2018~~take measures, weincluding ~~entered~~the ~~into~~suspension aof ~~consent~~cash ~~with~~distributions on our ~~Lenders~~common ~~related~~and tosubordinated ~~the~~units ~~Financing~~and ~~Agreement.~~cost ~~The~~and ~~consent includes the lenders~~productivity ~~agreement~~improvements, to ~~waive~~enhance ~~any~~and ~~Event~~preserve ofour ~~Default~~liquidity ~~that~~in ~~arose~~order orto ~~would~~fund ~~otherwise~~our ~~arise~~ongoing ~~under~~operations ~~the~~and ~~Financing~~necessary ~~Agreement~~capital ~~for failing to comply~~expenditures ~~with~~and ~~the~~meet ~~Fixed~~our ~~Charge~~financial ~~Coverage~~commitments ~~Ratio~~and ~~for~~debt ~~the~~service ~~six months ended September 30, 2018~~obligations.

OnRecent December 20, 2018, we entered into a limited waiver and consent (the “Waiver”) to the Financing Agreement. The Waiver relates to our sales of certain real property in Western Colorado, the net proceeds of which are required to be used to reduce the debt under the Financing Agreement. As of the date of the Waiver, we had sold 9 individual lots in smaller transactions. Rather than transmitting net proceeds with respect to each individual transaction, we agreed with the Lenders in principle to delay repayment until an aggregate payment could be made at the end of 2018. On December 18, 2018, we used the sale proceeds of approximately $379,000 to reduce the debt. The Waiver (i) contains a ratification by the Lenders of the sale of the individual lots to date and waives the associated technical defaults under the Financing Agreement for not making immediate payments of net proceeds therefrom, (ii) permits the sale of certain specified additional lots and (iii) subject to Lender consent, permits the sale of other lots on a going forward basis. The net proceeds of future sales will be held by us until a later date to be determined by the Lenders.Developments

OnPennyrile ~~February~~Mine ~~13,~~Complex ~~2019, we entered into a second amendment~~ (“~~Amendment~~Pennyrile”) toAsset ~~the~~Purchase ~~Financing~~ Agreement. The Amendment provides the Lender’s consent for us to pay a one-time cash distribution on February 14, 2019 to the Series A Preferred Unitholders an amount not to exceed approximately $3.2 million. The Amendment allows us to sell our remaining shares of Mammoth Energy Services, Inc. and utilize the proceeds for payment of the one-time cash distribution to the Series A Preferred Unitholders and waives the requirement to use such proceeds to prepay the outstanding principal amount outstanding under the Financing Agreement. The Amendment also waives any Event of Default that has or would otherwise arise under Section 9.01(c) of the Financing Agreement solely by reason of us failing to comply with the Fixed Charge Coverage Ratio covenant in Section 7.03(b) of the Financing Agreement for the fiscal quarter ending December 31, 2018. The Amendment includes an amendment fee of approximately $0.6 million payable by us on May 13, 2019 and an exit fee equal to 1% of the principal amount of the term loans made under the Financing Agreement that is payable on the earliest of (w) the final maturity date of the Financing Agreement, (x) the termination date of the Financing Agreement, (y) the acceleration of the obligations under the Financing Agreement for any reason, including, without limitation, acceleration in accordance with Section 9.01 of the Financing Agreement, including as a result of the commencement of an insolvency proceeding and (z) the date of any refinancing of the term loan under the Financing Agreement. The Amendment amends the definition of the Make-Whole Amount under the Financing Agreement to extend the date of the Make-Whole Amount period to December 31, 2019.

On September 6, 2019, we entered into an Asset Purchase Agreement (the “Pennyrile APA”) with Alliance Coal, LLC (“Buyer”) and Alliance Resource Partners, L.P. (“Buyer Parent”) pursuant to which we agreed to sell to Buyer all of the real property, permits, equipment and inventory and certain other assets associated with Pennyrile in exchange for approximately $3.7 million, subject to certain adjustments.

Pursuant to the Pennyrile APA, we retain liability for certain employee claims, subsidence claims arising from pre-closing mining operations, MSHA liabilities and certain other matters. The Pennyrile APA also provides that Buyer shall have the right to conduct diligence on the Pennyrile mine complex and may contest the fair market value of the purchased assets or the estimate of the costs of the assumed liabilities following such diligence investigation. In the event Buyer does contest such amounts, the parties will attempt to resolve the dispute and to the extent they cannot, will submit the matter to a third party to make a final determination with respect to such matters, and will adjust the purchase price accordingly.

The parties have made customary representations, warranties and covenants in the Pennyrile APA. The closing of the transactions contemplated by the Asset Purchase Agreement are subject to a number of closing conditions, including, among others, the performance of applicable covenants and accuracy of representations and warranties and absence of material adverse changes in the condition of Pennyrile. The transaction was completed during the first quarter of 2020.

~~Common~~Coal ~~Unit~~Supply ~~Warrants~~Asset Purchase Agreement

WeOn ~~entered~~September ~~into~~6, a2019, ~~warrant~~we ~~agreement~~entered ~~with~~into ~~certain~~an ~~parties~~Asset ~~that~~Purchase ~~are~~Agreement ~~also~~with ~~parties to~~ the ~~Financing~~Buyer ~~Agreement~~and ~~discussed~~Buyer ~~above.~~Parent ~~The~~for ~~warrant agreement included~~ the ~~issuance~~sale ofand aassignment ~~total~~ of certain ~~683,888~~coal ~~warrants~~supply ofagreements ~~our~~associated ~~common~~with ~~units~~Pennyrile (the “~~Common~~Coal ~~Unit~~Supply ~~Warrants~~APA”) atin ~~an exercise~~exchange ~~price~~for ofapproximately $17.953 million. ~~per~~The ~~unit,~~Coal ~~which~~Supply ~~was~~APA ~~the~~includes ~~closing~~customary ~~price~~representations of ~~our units on~~ the ~~OTC~~parties ~~market~~thereto ~~as of December 27, 2017. The Common Unit Warrants have a five year expiration date. The Common Unit Warrants~~ and ~~the~~indemnification ~~Rhino~~for ~~common~~losses ~~units after exercise are both transferable,~~arising ~~subject~~from ~~to applicable US securities laws. The Common Unit Warrant exercise price is $1.95 per unit, but~~ the ~~price~~breaches ~~per~~of ~~unit~~such ~~will be~~representations ~~reduced by future common unit distributions~~ and ~~other~~for ~~further~~liabilities ~~adjustments~~arising induring ~~price~~the ~~included~~period in which the ~~warrant~~relevant ~~agreement~~parties ~~for~~were ~~transactions~~not ~~that~~party ~~are dilutive~~ to the ~~amount~~coal ofsupply ~~Rhino’s common units outstanding~~agreements. The ~~warrant~~transactions ~~agreement~~contemplated ~~includes~~by ~~a provision for a cashless exercise where~~ the ~~warrant~~Coal ~~holders~~Supply ~~can~~APA ~~receive~~closed aupon ~~net number of common units. Per~~ the ~~warrant~~execution ~~agreement, the warrants are detached from the Financing Agreement and fully transferable~~thereof.

~~Letter~~Discontinued ~~of Credit Facility – PNC Bank~~Operations

OnThe ~~December~~Pennyrile ~~27,~~operating ~~2017,~~results we entered into a master letter of credit facility, security agreement and reimbursement agreement (the “LoC Facility Agreement”) with PNC Bank, National Association (“PNC”), pursuant to which PNC agreed to provide us with a facility for the ~~issuance~~year ofended ~~standby~~December letters of credit used in the ordinary course of our business (the “LoC Facility”). The LoC Facility Agreement provided that we pay a quarterly fee at a rate equal to 5% per annum calculated based on the daily average of letters of credit outstanding under the LoC Facility31, as2019 ~~well as administrative costs incurred by PNC~~ and a2018 ~~$100,000 closing~~are ~~fee.~~recorded ~~The LoC Facility Agreement provided that we reimburse PNC for any drawing under a letter of credit by a specified beneficiary~~ as ~~soon~~discontinued as possible after payment was made. Our obligations under the LoC Facility Agreement were secured by a first lien security interest on a cash collateral account that was required to contain no less than 105% of the face value of the outstanding letters of credit. In the event the amount in such cash collateral account was insufficient to satisfy our reimbursement obligationsoperations, ~~the~~ ~~amount~~including ~~outstanding would bear interest at~~ a ~~rate per annum equal to the Base Rate (as that term was defined in the LoC Facility~~ ~~Agreement) plus 2~~$38.~~0%.~~7 Wemillion ~~would~~impairment ~~indemnify~~loss ~~PNC~~associated ~~for~~with ~~any losses which PNC may have incurred as a result of~~ the ~~issuance of a letter of credit or PNC’s failure to honor any drawing under a letter of credit, subject in each case to certain exceptions~~sale. We provided cash collateral to our counterparties during the third quarter of 2018 and as of September 30, 2018, the LoC Facility was terminated. We had no outstanding letters of credit as of December 31, 2018.

Blackjewel Assignment Agreement

On August 14, 2019, our wholly owned subsidiary Jewell Valley Mining LLC, entered into a general assignment and assumption agreement and bill of sale (the “Assignment Agreement”) with Blackjewel L.L.C., Blackjewel Holdings L.L.C., Revelation Energy Holdings, LLC, Revelation Management Corp., Revelation Energy, LLC, Dominion Coal Corporation, Harold Keene Coal Co. LLC, Vansant Coal Corporation, Lone Mountain Processing LLC, Powell Mountain Energy, LLC, and Cumberland River Coal LLC (together, “Blackjewel”) to purchase certain assets from Blackjewel for cash consideration of $850,000 plus an additional royalty of $250,000 that is payable within one year from the date of the purchase, as well as the assumption of associated reclamation obligations. The assets that are subject of the Assignment Agreement consist of three underground mines in Virginia that were actively producing coal prior to Blackjewel’s filing for relief under Chapter 11 of the United States Bankruptcy Code, along with a preparation plant, rail loadout facility, related mineral and surface rights and infrastructure and certain purchase contracts to be assumed at our option. We resumed mining operations at two of the mines in the fourth quarter of 2019. The operating results of the mines are reported as part of our Central Appalachia segment.

Settlement Agreement

On June 28, 2019, we entered into a settlement agreement with a third party which allows the third party to maintain certain pipelines pursuant to designated permits at our Central Appalachia operations. The agreement required the third party to pay us $7.0 million in consideration. We received $4.2 million on July 3, 2019 and the balance of $2.8 million was paid on January 2, 2020. We recorded a gain of $6.9 million during the second quarter of 2019 related to this settlement agreement.

Financing Agreement

On February 13, 2019, we entered into a second amendment (“Amendment”) to the Financing Agreement. The Amendment provided the Lender’s consent for us to pay a one-time cash distribution on February 14, 2019 to the Series A Preferred Unitholders not to exceed approximately $3.2 million. The Amendment allowed us to sell our remaining shares of Mammoth Energy Services, Inc. (NASDAQ: TUSK)(“Mammoth Inc.”) and utilize the proceeds for payment of the one-time cash distribution to the Series A Preferred Unitholders and waived the requirement to use such proceeds to prepay the outstanding principal amount outstanding under the Financing Agreement. The Amendment also waived any Event of Default that has or would otherwise arise under Section 9.01(c) of the Financing Agreement solely by reason of us failing to comply with the Fixed Charge Coverage Ratio covenant in Section 7.03(b) of the Financing Agreement for the fiscal quarter ending December 31, 2018. The Amendment includes an amendment fee of approximately $0.6 million payable by us on May 13, 2019 and an exit fee equal to 1% of the principal amount of the term loans made under the Financing Agreement that is payable on the earliest of (w) the final maturity date of the Financing Agreement, (x) the termination date of the Financing Agreement, (y) the acceleration of the obligations under the Financing Agreement for any reason, including, without limitation, acceleration in accordance with Section 9.01 of the Financing Agreement, including as a result of the commencement of an insolvency proceeding and (z) the date of any refinancing of the term loan under the Financing Agreement. The Amendment amended the definition of the Make-Whole Amount under the Financing Agreement to extend the date of the Make-Whole Amount period to December 31, 2019.

On May 8, 2019, we entered into a third amendment (“Third Amendment”) to the Financing Agreement. The Third Amendment includes the Lenders’ agreement to waive any Event of Default that arose or would otherwise arise under the Financing Agreement for failing to comply with the Fixed Charge Coverage Ratio for the six months ended March 31, 2019. The Third Amendment increased the original exit fee of 3.0% to 6.0%. The original exit fee of 3% was included in the Financing Agreement at the execution date and the increase of the total exit fee to 6% was included as part of the amendment dated February 13, 2019 discussed above and this Third Amendment. The exit fee is applied to the principal amount of the loans made under the Financing Agreement that is payable on the earliest of (a) the final maturity date, (b) the termination date of the Financing agreement for any reason, (c) the acceleration of the obligations in the Financing Agreement for any reason and (d) the date of any refinancing of the term loan under the Financing Agreement.

On August 16, 2019, we entered into a fourth amendment (the “Fourth Amendment”) to the Financing Agreement originally executed on December 27, 2017 with the Lenders. The Fourth Amendment provided a $5.0 million term loan provided by the Lenders to us under the delayed draw feature of the Financing Agreement, and extended the period by which an applicable premium payable to the Lenders will be calculated to the final maturity date.

On September 6, 2019, we entered into a fifth amendment (the “Fifth Amendment”) to the Financing Agreement. The Fifth Amendment (i) extended the maturity of the Financing Agreement to December 27, 2022, (ii) provided a $5.0 million term loan provided by the Lenders to us under the delayed draw feature of the Financing Agreement, (iii) extended the period by which an applicable premium payable to the Lenders will be calculated to December 31, 2021, (iv) modified certain definitions and concepts to account for our recent acquisition of properties from Blackjewel, (v) permitted the disposition of the Pennyrile mining complex and (vi) provided for the payment of additional fees to the Lenders, including a consent fee of $1.0 million, an amendment fee of $825,000 and an increase in the lender exit fee of 1.00% to a total exit fee of 7.0% of the amount of term loans made under the Financing Agreement that is payable at the maturity of the Financing Agreement.

On March 2, 2020, we entered into a sixth amendment (the “Sixth Amendment”) to the Financing Agreement. The Sixth Amendment, among other things, provides a consent by the Origination Agent to a $3.0 million delayed draw term loan and increases the lender exit fee payable by the Partnership to the Lenders upon the maturity date (or earlier termination or acceleration date) by an additional 1.0%.

Distribution Suspension

~~Beginning~~Pursuant to the Partnership’s limited partnership agreement, our common units accrue arrearages every quarter when the distribution level is below the minimum level of $4.45 per unit. Beginning with the quarter ended June 30, 2015 and continuing through the quarter ended December 31, ~~2018~~2019, we have suspended the cash distribution on our common units. For each of the quarters ended September 30, 2014, December 31, 2014 and March 31, 2015, we announced cash distributions per common unit at levels lower than the minimum quarterly distribution. We have not paid any distribution on our subordinated units for any quarter after the quarter ended March 31, 2012. ~~The~~As ~~distribution suspension and prior reductions were the result~~ of ~~prolonged~~December ~~weakness~~31, ~~in the coal markets~~2019, ~~which~~we ~~has~~had ~~continued~~accumulated toarrearages ~~adversely~~of ~~affect~~$907.2 ~~our cash flow~~million.

Pursuant to our partnership agreement, our common units accrue arrearages every quarter when the distribution level is below the minimum level of $4.45 per unit. Since our distributions for the quarters ended September 30, 2014, December 31, 2014 and March 31, 2015 were below the minimum level and we altogether suspended the distribution beginning with the quarters ended June 30, 2015 through December 31, 2018, we have accumulated arrearages at December 31, 2018 related to the common unit distribution of approximately $673.1 million.

History

Our predecessor was formed in April 2003 by Wexford Capital. We were formed in April 2010 to own and control the coal properties and related assets owned by Rhino Energy LLC. On October 5, 2010, we completed our IPO. Our common units were originally listed on the New York Stock Exchange under the symbol “RNO”. In connection with the IPO, Wexford contributed their membership interests in Rhino Energy LLC to us, and in exchange we issued subordinated units representing limited partner interests in us and common units to Wexford and issued incentive distribution rights to our general partner. Through a series of transactions completed in the first quarter of 2016, Royal Energy Resources, Inc. (“Royal”) acquired a majority ownership and control of the Partnership and 100% ownership of the Partnership’s general partner.

Since April 2003, we have completed numerous coal asset acquisitions with a total purchase price of approximately $357.5 million. Through these acquisitions and coal lease transactions, we have substantially increased our proven and probable coal reserves and non-reserve coal deposits. In addition, we have successfully grown our production through internal development projects.

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

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

Coal Operations

Mining and Leasing Operations

As of December 31, ~~2018~~2019, we operated ~~two~~three mining complexes located in Central Appalachia (Tug River, ~~and~~ Rob Fork and Jewell Valley). In addition during ~~2018~~ 2019, we operated one mining complex located in Northern Appalachia (Hopedale). ~~The other Northern Appalachia mining complex, Sands Hill Mining, was sold in November 2017.~~ In the Western Bituminous region, we operated one mining complex located in Emery and Carbon Counties, Utah (Castle Valley). WeDuring the year, we also operated a mining complex in the Illinois Basin, our Riveredge mine at our Pennyrile mining complex. (~~See~~Please ~~Note~~read 4above ~~of the consolidated financial statements included elsewhere in this annual report~~ for ~~further information~~additional information on the disposition of ~~Sands~~the ~~Hill~~Pennyrile ~~Mining~~mining complex).

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

4The following map shows the location of our coal mining and leasing operations as of December 31, 2019 (Note: the McClane Canyon mine in Colorado was permanently idled at December 31, 2013):

The following map shows the location of our coal mining and leasing operations as of December 31, 2018 (Note: the McClane Canyon mine in Colorado was permanently idled at December 31, 2013):

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

The following table summarizes our mining complexes and production from continuing operations by region as of December 31, 2019, 2018 and 2017.

Region

Preparation Plants and Loadouts

Transportation to ~~Customers~~customers (1)

Number and Type of Active Mines (2)

~~Tons Produced for the Year Ended December 31, 2018 (3)~~

Tons Produced for the Year Ended December 31, 2019 (3)

Tons Produced for the Year Ended December 31, 2018 (3)

Tons Produced for the Year Ended December 31, 2017 (3)

(in million tons)

Central Appalachia

Tug River Complex (KY, WV)

Tug Fork & Jamboree(4)

Truck, Barge, Rail (NS)

~~1.2~~

1.2

0.9

Rob Fork Complex (KY)

Rob Fork

Truck, Barge, Rail (CSX)

1U,1S

~~0.5~~

0.4

0.5

0.6

Northern Appalachia(5)

Jewell Valley Complex) (VA)

Flatrock Plant & Raven Loadout

Truck

—

Hopedale Complex (OH)

Nelms

Truck, Rail (OHC, WLE)

0.4

Northern Appalachia(5)

Illinois Basin

Hopedale Complex (OH)

Nelms

Truck, Rail (OHC, WLE)

0.5

0.4

Taylorville Field (IL)

n/a

Rail (NS)

—

Illinois Basin

Pennyrile Complex (KY)

Preparation plant & river loadout

Barge

1.3

Taylorville Field (IL)

n/a

Rail (NS)

—

Western Bituminous

Pennyrile Complex (KY) (7)

n/a

Castle Valley Complex (UT)

Truck loadout

Truck

1.0

Western Bituminous

McClane Canyon Mine (CO)(6)

n/a

Truck

—

Castle Valley Complex (UT)

Truck loadout

Truck

1.1

1.0

Total

4U,3S

4.4

McClane Canyon Mine (CO)(6)

n/a

Truck

—

Total

5U,3S

3.2

3.1

2.9

~~(1)~~	~~NS = Norfolk Southern Railroad; CSX = CSX Railroad; OHC = Ohio Central Railroad; WLE = Wheeling & Lake Erie Railroad.~~(1)	NS = Norfolk Southern Railroad; CSX = CSX Railroad; OHC = Ohio Central Railroad; WLE = Wheeling & Lake Erie Railroad.
~~(2)~~	~~Numbers indicate the number of active mines. U = underground; S = surface. All of our mines as of December 31, 2018 were company-operated.~~(2)	Numbers indicate the number of active mines. U = underground; S = surface. All of our mines as of December 31, 2019 were company-operated.
~~(3)~~	~~Total production based on actual amounts and not rounded amounts shown in this table.~~(3)	Total production based on actual amounts and not rounded amounts shown in this table.
~~(4)~~	~~Jamboree includes only a loadout facility.~~(4)	Jamboree includes only a loadout facility.
~~(5)~~	~~The Sands Hill Mining complex was previously included in our Northern Appalachia region and was sold in November 2017.~~(5)	The Sands Hill Mining complex was previously included in our Northern Appalachia region and was sold in November 2017.
~~(6)~~	~~The McClane Canyon mine was permanently idled as of December 31, 2013.~~(6)	The McClane Canyon mine was permanently idled as of December 31, 2013.
	(7)	The Pennyrile mining complex was sold in September 2019. The operating results for the year ended December 31, 2019 are included as discontinued operations in this Form 10-K.

Central Appalachia. ~~For~~As ~~the~~of ~~year ended~~ December 31, ~~2018~~2019, we operated ~~two~~three mining complexes located in Central Appalachia consisting of ~~one~~ three active underground ~~mine~~mines and three surface mines. For the year ended December 31, ~~2018~~2019, the mines at our Tug River and Rob ~~Fork~~ Fork mining complexes produced an aggregate of approximately 1.21 million tons of steam coal and an estimated 0.5 million tons of metallurgical coal. Two of the underground mines at our Jewell Valley mining complex produced approximately 15,000 tons of mid-vol metallurgical coal during the fourth quarter of 2019.

Tug River Mining Complex. Our Tug River mining complex is located in Kentucky and West Virginia bordering the Tug River. This complex produces coal from two company-operated surface mines, which includes one high-wall mining unit. Coal production from these operations is delivered to the Tug Fork preparation plant for processing and then transported by truck to the Jamboree rail loadout for blending and shipping. Coal suitable for direct-ship to customers is delivered by truck directly to the Jamboree rail loadout from the mine sites. The Tug Fork plant is a modern, 350 tons per hour preparation plant utilizing heavy media circuitry that is capable of cleaning coarse and fine coal size fractions. The Jamboree loadout is located on the Norfolk Southern Railroad and is a modern unit train, batch weigh loadout. This mining complex produced approximately 1.0.9 million tons of steam coal and approximately 0.23 million tons of metallurgical coal for the year ended December 31, ~~2018~~2019.

Rob Fork Mining Complex. Our Rob Fork mining complex is located in eastern Kentucky and produces coal from one company-operated surface mine and one company-operated underground mine. The Rob Fork mining complex is located on the CSX Railroad and consists of a modern preparation plant utilizing heavy media circuitry that is capable of cleaning coarse and fine coal size fractions and a unit train loadout with batch weighing equipment. The mining complex has significant blending capabilities allowing the blending of raw coals with washed coals to meet a wide variety of customers’ needs. The Rob Fork mining complex produced approximately 0.21 million tons of steam coal and 0.3 million tons of metallurgical coal for the year ended December 31, ~~2018~~2019.

~~Northern~~Jewell ~~Appalachia.~~Valley ~~For~~Mining ~~the~~Complex. ~~year~~Our ~~ended~~Jewell ~~December~~Valley ~~31,~~mining ~~2018,~~complex we(purchased ~~operated~~in ~~one~~2019) ~~mining~~is ~~complex~~ located in ~~Northern~~the ~~Appalachia~~western ~~consisting~~ part of ~~one~~Virginia and produces coal from two company-operated underground ~~mine~~mines. ~~For~~The ~~the~~Jewell ~~year~~Valley ~~ended~~mining ~~December~~complex ~~31, 2018, the mine~~ produced ~~an aggregate of~~ approximately ~~0.4~~ ~~million~~15,000 tons of ~~steam~~mid-vol metallurgical coal. Wefor ~~sold~~the ~~our~~year ~~Sands~~ended ~~Hill~~December ~~Mining operation in November 2017~~31, ~~which consisted of one company-operated surface mine~~2019.

~~Hopedale~~Northern ~~Mining Complex~~Appalachia. ~~The~~For ~~Hopedale~~the ~~mining~~year ~~complex~~ended ~~includes~~December ~~an underground mine located in Hopedale~~31, ~~Ohio approximately five miles northeast of Cadiz~~2019, ~~Ohio.~~we ~~Coal~~operated ~~produced~~one ~~from~~mining ~~the~~complex ~~Hopedale mine is cleaned at our Nelms preparation plant~~ located onin ~~the~~Northern ~~Ohio~~Appalachia ~~Central~~consisting ~~Railroad~~of ~~and~~one ~~the~~company-operated ~~Wheeling~~underground &mine. ~~Lake~~For ~~Erie~~the ~~Railroad~~year ~~and~~ended ~~then~~December ~~shipped~~31, by2019, ~~train~~the ormine ~~truck~~produced toan ~~our~~aggregate ~~customers.~~of ~~The infrastructure includes a full-service loadout facility. This underground mining operation produced~~ approximately 0.45 million tons of steam coal ~~for the year ended December 31, 2018~~.

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 cleaned at our Nelms preparation plant located on the Ohio Central Railroad and the Wheeling & Lake Erie Railroad and then shipped by train or truck to our customers. The infrastructure includes a full-service loadout facility. This underground mining operation produced approximately 0.5 million tons of steam coal for the year ended December 31, 2019.

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

Castle Valley Mining Complex. Our Castle Valley mining complex includes one underground mine located in Emery and Carbon Counties, Utah and include coal reserves and non-reserve coal deposits, underground mining equipment and infrastructure, an overland belt conveyor system, a loading facility and support facilities. We produced approximately 1.0 million tons of steam coal from one underground mine at this complex for the year ended December 31, 2018.

Illinois Basin. We operate one mining complex in the Illinois Basin region that produces coal from an underground mine located in Daviess and McLean counties in western Kentucky contiguous to the Green River. We also have an estimated 111.1 million of proven and probable reserves in the Taylorville Field area in the Illinois Basin that remain undeveloped.

Pennyrile Mining Complex. In mid-2014, we completed the initial construction of a new underground mining operation on the purchased property, referred to as our Pennyrile mining complex, which includes one underground mine, a preparation plant and river loadout facility. The property is adjacent to a navigable waterway, which allows for exports to non-U.S. customers. We produced approximately 1.3 million tons of steam coal from this mine for the year ended December 31, 2018. We believe the possibility exists to expand production up to 2.0 million tons per year with further development of the mine at the Pennyrile complex.

Castle Valley Mining Complex. Our Castle Valley mining complex includes one underground mine located in Emery and Carbon Counties, Utah and include coal reserves and non-reserve coal deposits, underground mining equipment and infrastructure, an overland belt conveyor system, a loading facility and support facilities. We produced approximately 1.1 million tons of steam coal from one underground mine at this complex for the year ended December 31, 2019.

Illinois Basin. We operated one mining complex in the Illinois Basin region (Pennyrile) that produced coal from an underground mine located in Daviess and McLean counties in western Kentucky contiguous to the Green River. We discontinued operations at Pennyrile during the third quarter of 2019. Please see above for additional details. We also have an estimated 111.1 million of proven and probable reserves in the Taylorville Field area in the Illinois Basin that remains undeveloped.

Other Non-Mining Operations

In addition to our mining operations, we operate various subsidiaries which provide auxiliary services for our coal mining operations. Rhino Services is responsible for mine-related construction, site and roadway maintenance and post-mining reclamation. Through Rhino Services, we plan and monitor each phase of our mining projects as well as the post-mining reclamation efforts. We also perform the majority of our drilling and blasting activities at our company-operated surface mines in-house rather than contracting to a third party.

Other Natural Resource Assets

Oil and Natural Gas

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

In December 2012, we made an initial investment in a new joint venture, Muskie Proppant LLC (“Muskie”), with affiliates of Wexford Capital. In November 2014, we contributed our investment interest in Muskie to Mammoth Energy Partners LP (“Mammoth”) in return for a limited partner interest in Mammoth. In October 2016, we contributed our limited partner interests in Mammoth to Mammoth, Inc. in exchange for 234,300 shares of common stock of Mammoth, Inc.

In September 2014, we made an initial investment of $5.0 million in a new joint venture, Sturgeon Acquisitions LLC (“Sturgeon”), with affiliates of Wexford Capital and Gulfport Energy Corporation (NASDAQ: GPOR) (“Gulfport”). We accounted for the investment in this joint venture and results of operations under the equity method based upon our ownership percentage. We recorded our proportionate share of the operating income for this investment for the year ended December 31, 2017 of approximately $36,000. In June 2017, we contributed our limited partner interests in Sturgeon to Mammoth Inc. in exchange for 336,447 shares of common stock of Mammoth Inc. As of December 31, 2018, we owned 104,100 shares of Mammoth Inc. Our remaining shares of Mammoth Inc. were sold during 2019.

As of December 31, 2018 ~~and 2017~~, we recorded our investment in Mammoth Inc. as a current asset, which was classified as available-for-sale. We have included our investment in Mammoth Inc. in the Other category for segment reporting purposes for the year ended December 31, 2018.

Coal Customers

General

Our primary customers for our steam coal are electric utilities and industrial consumers, and the metallurgical coal we produce is sold primarily to domestic and international steel producers and coal brokers. For the year ended December 31, ~~2018~~2019, approximately 8182.0% of our coal sales tons consisted of steam coal and approximately 1918.0% consisted of metallurgical coal. For the year ended December 31, ~~2018~~2019, approximately 4045.0% of our coal sales tons that we produced were sold to electric utilities. The majority of our electric utility customers purchase coal for terms of one to three years, but we also supply coal on a spot basis for some of our customers. For the year ended December 31, ~~2018~~2019, we derived approximately 8073.02% of our total coal revenues from sales to our ten largest customers, with affiliates of our top three customers accounting for approximately 4038.43% of our coal revenues for that period. The above percentages include coal sales from discontinued operations related to our Pennyrile operation.

Coal Supply Contracts

For the years ended December 31, 2018 and 2017, approximately 64% and 59%, respectively, of our aggregate coal tons sold were sold through supply contracts. We expect to continue selling a significant portion of our coal under supply contracts. As of December 31, 2018, we had commitments under supply contracts to deliver annually scheduled base quantities as follows:

Year	Tons (in thousands)		Number of customers
2019		3,699		18
2020		1,979		6
2021		352		2

Coal Supply Contracts

For the years ended December 31, 2019 and 2018, approximately 82% and 64%, respectively, of our aggregate coal tons sold were sold through supply contracts. We expect to continue selling a significant portion of our coal under supply contracts. As of December 31, 2019, we had commitments under supply contracts to deliver annually scheduled base quantities as follows:

Year	Tons		Number of customers
		(in thousands)
2020		1,734		12
2021		400		3
2022		250		3

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

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

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

Transportation

We ship coal to our customers by rail, truck or barge. A significant portion of our coal is transported to customers by either the CSX Railroad or the Norfolk Southern Railroad in eastern Kentucky and by the Ohio Central Railroad or the Wheeling & Lake Erie Railroad in Ohio. We use third-party trucking to transport coal to our customers in Utah. ~~For our Pennyrile complex in western Kentucky, coal is transported to our customers via barge from our river loadout on the Green River located on our Pennyrile mining complex.~~ In addition, coal from certain ~~of our~~ Central Appalachia mines is located within economical trucking distance to the Big Sandy River and can be transported by barge. It is customary for customers to pay the transportation costs to their location.

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

Suppliers

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

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

Competition

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

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

Regulation and Laws

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

	●	employee health and safety;

	●	governmental approvals and other authorizations such as mine permits, as well as other licensing requirements;

	●	air quality standards;

	●	water quality standards;

	●	storage, treatment, use and disposal of petroleum products and other hazardous substances;

	●	plant and wildlife protection;

	●	reclamation and restoration of mining properties after mining is completed;

	●	the discharge of materials into the environment, including waterways or wetlands;

	●	storage and handling of explosives;

	●	wetlands protection;

	●	surface subsidence from underground mining;

	●	the effects, if any, that mining has on groundwater quality and availability; and

	●	legislatively mandated benefits for current and retired coal miners.

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

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

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

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. 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. 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.

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

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

For the year ended December 31, ~~2018~~2019 our average MSHA violations per inspection day was 0.3944 as compared to the most recent national average of 0.5961 violations per inspection day for coal mining activity as reported by MSHA, or 3327.8987% below this national average.

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

In addition, more stringent mine safety laws and regulations promulgated by the 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.

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

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From time to time, certain portions of individual mines have been required to suspend or shut down operations temporarily in order to address a compliance requirement or because of an accident. For instance, MSHA issues orders pursuant to Section 103(k) that, among other things, call for operations in the area of the mine at issue to suspend operations until compliance is restored. Likewise, if an accident occurs within a mine, the MSHA requirements call for all operations in that area to be suspended until the circumstance leading to the accident has been resolved. During the fiscal year ended December 31, 2019 (as in earlier years), we received such orders from government agencies and have experienced accidents within our mines requiring the suspension or shutdown of operations in those particular areas until the circumstances leading to the accident have been resolved. While the violations or other circumstances that caused such an accident were being addressed, other areas of the mine could and did remain operational. These circumstances did not require us to suspend operations on a mine-wide level or otherwise entail material financial or operational consequences for us. Any suspension of operations at any one of our locations that may occur in the future may have material financial or operational consequences for us.

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

Black Lung Laws

Under the Black Lung Benefits Act of 1977 and the Black Lung Benefits Reform Act of 1977, as amended in 1981, coal mine operators must make payments of black lung benefits to current and former coal miners with black lung disease, some survivors of a miner who dies from this disease, and to fund a trust fund for the payment of benefits and medical expenses to claimants who last worked in the industry prior to January 1, 1970. To help fund these benefits, a tax is levied on production of $01.5010 per ton for underground-mined coal and $0.2555 per ton for surface-mined coal, but not to exceed 24.04% of the applicable sales price (rates effective January 1, ~~2019~~2020). This excise tax does not apply to coal that is exported outside of the United States. In ~~2018~~2019, we recorded approximately $21.5 million of expense related to this excise tax, which includes the amount paid for our Pennyrile operation that was discontinued in the third quarter of 2019.

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

Workers’ Compensation

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

Workers’ Compensation

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

Surface Mining Control and Reclamation Act (“SMCRA”)

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

SMCRA and similar state statutes require, among other things, that mined property be restored in accordance with specified standards and approved reclamation plans. The act requires that we restore the surface to approximate the original contours as soon as practicable upon the completion of surface mining operations. The mine operator must submit a bond or otherwise secure the performance of these reclamation obligations. Mine operators can also be responsible for replacing certain water supplies damaged by mining operations and repairing or compensating for damage to certain structures occurring on the surface as a result of mine subsidence, a consequence of long-wall mining and possibly other mining operations. In addition, the Abandoned Mine Lands Program, which is part of SMCRA, imposes a tax on all current mining operations, the proceeds of which are used to restore mines closed prior to SMCRA’s adoption in 1977. The maximum tax for the period from October 1, 2012 through September 30, 2021, has been decreased to 28 cents per ton on surface mined coal and 12 cents per ton on underground mined coal. However, this fee is subject to change. Should this fee be increased in the future, 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, ~~2018~~2019, we had accrued approximately $1820.56 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 basis to deny the issuance of new mining permits or modifications of existing mining permits, although we know of no basis by which we would be (and we are not now) permit-blocked.

In addition, a February 2014 decision by the U.S. District Court for the District of Columbia invalidated the Office of Surface Mining Reclamation and Enforcement’s (“OSM”) 2008 Stream Buffer Zone Rule, which prohibited mining disturbances within 100 feet of streams, subject to various exemptions. In December 2016, the OSM published the final Stream Protection Rule, which, among other things, would have required 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, the rule was revoked pursuant to the Congressional Review Act. Accordingly, the rule “shall have no force or effect” and OSM cannot promulgate a substantially similar rule absent future legislation. Whether Congress will enact future legislation to require a new Stream Protection Rule remains uncertain. A new Stream Protection Rule, or other new SMCRA regulations, could result in additional material costs, obligations, and restrictions associated with our operations.

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 bond issuers may refuse to renew bonds or may demand additional collateral upon those renewals. Our failure to maintain, or inability to acquire, surety bonds that are required by state and federal laws would have a material adverse effect on our ability to produce coal, which could affect our profitability and cash flow.

As of December 31, ~~2018~~2019, we had approximately $4241.6 million in surety bonds outstanding to secure the performance of our reclamation obligations. Of the $4241.6 million, approximately $0.4 million relates to surety bonds for Deane Mining, LLC ~~and approximately $3.4 million relates to surety bonds for Sands Hill Mining~~, ~~LLC,~~ which ~~in each case~~ have not been transferred or replaced by the ~~buyers~~ buyer of Deane Mining, LLC ~~or Sands Hill Mining, LLC~~ as was agreed to by the parties as part of the ~~transactions~~transaction. We can provide no assurances that a surety company will underwrite the surety bonds of the ~~purchasers~~purchaser of ~~these~~Deane ~~entities~~Mining LLC, nor are we aware of the actual amount of reclamation at any given time. Further, if there was a claim under these surety bonds prior to the transfer or replacement of such bonds by the ~~buyers~~buyer of Deane Mining, ~~LLC~~ ~~or Sands Hill Mining,~~ LLC, ~~then~~ we may be responsible to the surety company for any amounts it pays in respect of such claim. While the ~~buyers~~buyer ~~are~~is required to indemnify us for damages, including reclamation liabilities, pursuant to the agreements governing the sales of ~~these~~this ~~entities~~entity, we may not be successful in obtaining any indemnity or any amounts received may be inadequate.

Air Emissions

The federal Clean Air Act (the “CAA”) and similar state and local laws and regulations, which regulate emissions into the air, affect coal mining operations both directly and indirectly. The CAA directly impacts our coal mining and processing operations by imposing permitting requirements and, in some cases, requirements to install certain emissions control equipment, on sources that emit various hazardous and non-hazardous air pollutants. The CAA also indirectly affects coal mining operations by extensively regulating the air emissions of coal-fired electric power generating plants and other industrial consumers of coal, including air emissions of sulfur dioxide, nitrogen oxides, particulates, mercury and other compounds. There have been a series of recent federal rulemakings from the U.S. Environmental Protection Agency, or EPA, which are focused on emissions from coal-fired electric generating facilities. For example, in June 2015, the United States Supreme Court decided Michigan v. the EPA, which held that the EPA should have considered the compliance costs associated with its Mercury and Air Toxics Standards, or MATS, in deciding to regulate power plants under Section 112(n)(1) of the Clean Air Act. The Court did not vacate the MATS rule, and MATS has remained in place. In April 2016, EPA published its final supplemental finding that it is “appropriate and necessary” to regulate coal and oil-fired units under Section 112 of the Clean Air Act. That finding was challenged in court, but the rule remained in effect. In April 2017, the D.C. Circuit agreed to EPA’s request to delay proceedings while the EPA reviewed the supplemental finding to determine whether it should be maintained, modified, or otherwise reconsidered. In December 2018, the EPA issued a proposed revised Supplemental Cost Finding for the MATS rule proposing to determine that it is not “appropriate and necessary” to regulate Hazardous Air Pollutant (“HAP”) emissions from power plants under Section 112 of the Clean Air Act. The EPA did not propose, however, to rescind or repeal the HAP emission standards and other requirements of the MATS rule, which would remain in place under the proposal. Installation of additional emissions control technology and additional measures required under laws and regulations related to air emissions will make it more costly to operate coal-fired power plants and possibly other facilities that consume coal and, depending on the requirements of individual state implementation plans, or SIPs, could make coal a less attractive fuel alternative in the planning and building of power plants in the future.

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

● The EPA’s Acid Rain Program, provided in Title IV of the CAA, regulates emissions of sulfur dioxide from electric generating facilities. Sulfur dioxide is a by-product of coal combustion. Affected facilities purchase or are otherwise allocated sulfur dioxide emissions allowances, which must be surrendered annually in an amount equal to a facility’s sulfur dioxide emissions in that year. Affected facilities may sell or trade excess allowances to other facilities that require additional allowances to offset their sulfur dioxide emissions. In addition to purchasing or trading for additional sulfur dioxide allowances, affected power facilities can satisfy the requirements of the EPA’s Acid Rain Program by switching to lower sulfur fuels, installing pollution control devices such as flue gas desulfurization systems, or “scrubbers,” or by reducing electricity generating levels. ● On July 6, 2011, the EPA finalized the Cross State Air Pollution Rule (“CSAPR”), which requires the District of Columbia and 27 states from Texas eastward (not including the New England states or Delaware) to significantly improve air quality by reducing power plant emissions that cross state lines and contribute to ozone and/or fine particle pollution in other states. In September 2016, EPA finalized the CSAPR Rule Update for the 2008 ozone national air quality standards (“NAAQS”). The rule aims to reduce summertime NOx emissions from power plants in 22 states in the eastern United States. ~~Consolidated judicial challenges to the rule are now pending in the D.C. Circuit Court of Appeals.~~ ● In addition, in January 2013, the EPA issued final MACT standards for several classes of boilers and process heaters, including large coal-fired boilers and process heaters (Boiler MACT), which require significant reductions in the emission of particulate matter, carbon monoxide, hydrogen chloride, dioxins and mercury. Various legal challenges were filed and EPA promulgated a revised final rule in November 2015. In December 2016, the D.C. Circuit remanded the Boiler MACT standards to the EPA requiring the agency to revise emissions standards for certain boiler subcategories. The ~~court determined that the existing MACT standards should remain in place while the revised standards are being developed, but did not establish a deadline for the~~ EPA to complete the rulemaking. In June 2017, the U.S. Supreme Court declined to review the D.C. Circuit ruling. We cannot predict the outcome of any legal challenges that may be filed in the future. Before reconsideration, the EPA estimated that the rule would affect 1,700 existing major source facilities with an estimated 14,316 boilers and process heaters. Some owners will make capital expenditures to retrofit boilers and process heaters, while a number of boilers and process heaters will be prematurely retired. The retirements are likely to reduce the demand for coal. The impact of the regulations will depend on the outcome of future legal challenges and EPA actions that cannot be determined at this time. ● The EPA has adopted new, more stringent NAAQS for ozone, fine particulate matter, nitrogen dioxide and sulfur dioxide. As a result, some states will be required to amend their existing SIPs to attain and maintain compliance with the new air quality standards. For example, in June 2010, the EPA issued a final rule setting forth a more stringent primary NAAQS applicable to sulfur dioxide. The rule also modifies the monitoring increment for the sulfur dioxide standard, establishing a 1-hour standard, and expands the sulfur dioxide monitoring network. Initial non-attainment determinations related to the 2010 sulfur dioxide rule were published in August 2013 with an effective date in October 2013. States with non-attainment areas had to submit their SIP revisions in April 2015, which must meet the modified standard by summer 2017. For all other areas, states will be required to submit “maintenance” SIPs. EPA finalized its PM2.5 NAAQS designations in December 2014. Individual states must now identify the sources of PM2.5 emissions and develop emission reduction plans, which may be state-specific or regional in scope. Nonattainment areas must meet the revised standard no later than 2021. More recently, in October 2015, the EPA lowered the NAAQS for ozone from 75 to 70 parts per billion for both the 8-hour primary and secondary standards. Significant additional emissions control expenditures will likely be required at coal-fired power plants and coke plants to meet the new standards. The EPA completed area designations for the 2015 ozone standards in July 2018. Because coal mining operations and coal-fired electric generating facilities emit particulate matter and sulfur dioxide, our mining operations and customers could be affected when the standards are implemented by the applicable states. Moreover, we could face adverse impacts on our business to the extent that these and any other new rules affecting coal-fired power plants result in reduced demand for coal.

●

In June 2005, the EPA amended its regional haze program to improve visibility in national parks and wilderness areas. Affected states were required to develop SIPs by December 2007 that, among other things, were to identify facilities that would have to reduce emissions and comply with stricter emission limitations. The vast majority of states failed to submit their plans by the December 2017 deadline. The EPA ultimately agreed in a consent decree with environmental groups to impose regional haze federal implementation plans or to take action on regional haze SIPs before the agency for 42 states and the District of Columbia. The EPA has completed those actions for all but several states in its first planning period (2008-2010). The continued implementation of this program has restricted and may continue to restrict construction of new coal-fired power plants where emissions are projected to reduce visibility in protected areas and may require certain existing coal-fired power plants to install emissions control equipment to reduce haze-causing emissions such as sulfur dioxide, nitrogen oxide, and particulate matter. Consequently, demand for our steam coal could be affected. However, in January 2018 EPA announced that it was revisiting the 2017 Regional Haze Rule revisions, and announced an intent to commence a new rulemaking. In September 2018, EPA released the Regional Haze Reform Roadmap directing EPA staff to take certain actions to ensure adequate support for states to enable timely and effective implementation of the regional haze program and announcing EPA’s intent to issue new guidance and continue exploring further regulatory EPA by July 2021, to address visibility impairment for the second implementation period, which ends in 2028.

● In June 2005, the EPA amended its regional haze program to improve visibility in national parks and wilderness areas. Affected states were required to develop SIPs by December 2007 that, among other things, were to identify facilities that would have to reduce emissions and comply with stricter emission limitations. The vast majority of states failed to submit their plans by the December 2017 deadline. The EPA ultimately agreed in a consent decree with environmental groups to impose regional haze federal implementation plans or to take action on regional haze SIPs before the agency for 42 states and the District of Columbia. The EPA has completed those actions for all but several states in its first planning period (2008-2010). The continued implementation of this program may restrict construction of new coal-fired power plants where emissions are projected to reduce visibility in protected areas and may require certain existing coal-fired power plants to install emissions control equipment to reduce haze-causing emissions such as sulfur dioxide, nitrogen oxide, and particulate matter. Consequently, demand for our steam coal could be affected. However, in January 2018 EPA announced that it was revisiting the 2017 Regional Haze Rule revisions, and announced an intent to commence a new rulemaking. In September 2018, EPA released the Regional Haze Reform Roadmap directing EPA staff to take certain actions to ensure adequate support for states to enable timely and effective implementation of the regional haze program and announcing EPA’s intent to issue new guidance and continue exploring further regulatory changes. Accordingly, future implementation of these rules is unclear.

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

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

Climate Change

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

On the international level, the United States was 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; however, in August 2017 the U.S. State Department officially informed the United Nations of the intent of the U.S. to withdraw from the agreement, with the earliest possible effective date of withdrawal being November 4, 2020. Despite the planned withdrawal, certain U.S. city and state governments have announced their intention to satisfy their proportionate obligations under the Paris Agreement. These commitments could further reduce demand and prices for coal.

17At the Federal level, EPA has taken a number of steps to regulate GHG emissions. For example, in August 2015, the EPA issued its final Clean Power Plan (the “CPP”) rules setting carbon pollution standards for power plants. The U.S. Supreme Court stayed the implementation of the CPP in February 2016. In June 2019, EPA finalized the proposed Affordable Clean Energy (“ACE”) Rule to replace the CPP, provide states with authority to regulate GHGs from coal-fired power plants, and establish heat rate improvements as the best system of emissions reduction. The ACE rule has been challenged in court and the final outcome of that litigation is uncertain. If the ACE Rule results in state plans to significantly reduce the level of GHG emissions from electric utility generating units, or if EPA implements more stringent regulations in the future, demand for coal will likely decrease. 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”). In December 2018, EPA proposed a rule amending its prior determination that carbon capture and sequestration is the best system of emission reduction. However, if that rule is not finalized, or if other legal actions require fossil fuel-fired power plants to use of carbon capture and storage technology, the demand for coal may decrease. In addition, passage of any comprehensive federal climate change and energy legislation could impact the demand for coal. Any reduction in the amount of coal consumed by North American electric power generators could reduce the price of coal that we mine and sell, thereby reducing our revenues and materially and adversely affecting our business and results of operations.

AtMany ~~the~~states ~~Federal~~and ~~level,~~regions ~~EPA~~have ~~has~~adopted ~~taken~~greenhouse agas ~~number~~initiatives ofand ~~steps~~certain togovernmental ~~regulate~~bodies ~~GHG~~have ~~emissions.~~or ~~For~~are ~~example,~~considering ~~in August 2015,~~ the ~~EPA~~imposition of ~~issued~~fees ~~its final~~or ~~Clean~~taxes ~~Power~~based ~~Plan~~on (the ~~“CPP”)~~emission ~~rules~~of ~~that~~greenhouse ~~establish~~gases ~~carbon~~by ~~pollution~~certain ~~standards for power plants~~facilities, ~~called~~including ~~CO2 emission~~coal-fired ~~performance~~electric ~~rates.~~generating ~~Judicial challenges led the U~~facilities.~~S. Supreme Court to grant a stay of the implementation of the~~ ~~CPP~~For ~~in February 2016. By its terms~~example, ~~this~~ten ~~stay~~northeastern ~~will~~states ~~remain~~formed inthe ~~effect~~Regional ~~throughout~~Greenhouse ~~the~~Gas ~~pendency~~Initiative ofagreement ~~the~~(“RGGI”) ~~appeals~~aimed ~~process.~~at ~~The Supreme~~reducing ~~Court’s~~carbon ~~stay~~dioxide ~~applies only to EPA’s regulations for CO2~~ emissions from ~~existing~~ power plants ~~and will not affect EPA’s standards for new power plants~~. ItRGGI isimposes ~~not~~a ~~yet~~cap ~~clear~~on ~~how~~emissions ~~the~~of ~~courts~~carbon ~~will~~dioxide ~~rule~~ on ~~the~~all ~~legality~~fossil-fuel offired ~~the CPP. Additionally,~~electric ingenerating ~~October~~facilities ~~2017~~that ~~EPA~~are ~~proposed~~25 toMW ~~repeal~~or ~~the~~larger ~~CPP,~~and ~~although~~allows ~~the~~for ~~final~~trades ~~outcome~~ of ~~this~~carbon ~~action~~dioxide ~~and~~emissions in the ~~pending~~participating ~~litigation regarding~~states. ~~the~~The ~~CPP~~RGGI iscarbon ~~uncertain~~dioxide attrading ~~this~~program ~~time.~~began ~~In connection~~ with ~~the~~auctions ~~proposed~~for ~~repeal,~~carbon ~~EPA~~dioxide ~~issued~~allowances ~~an Advance Notice of Proposed Rulemaking (“ANPRM”)~~ in ~~December~~September ~~2017 regarding emission guidelines to limit GHG emissions from existing electricity utility generating units~~2008. InNew ~~August~~Jersey ~~2018, the EPA issued the proposed Affordable Clean Energy (“ACE”) Rule, which would replace~~rejoined ~~the~~RGGI ~~CPP.~~in If2019 ~~the~~after ~~ACE~~leaving ~~Rule~~in is2011 ~~finalized, it will likely be subject to judicial challenge. If the effort to repeal the CPP is unsuccessful~~ and ~~the~~several ~~rules~~additional ~~were~~northeastern ~~upheld~~states ~~at the conclusion of the appellate process~~ and ~~were~~Canadian ~~implemented~~provinces inhave ~~their~~joined ~~current~~as ~~form~~ participants or ifobservers ~~the~~since ~~ACE Rule~~its ~~results~~inception. inIn ~~state plans to reduce the level of GHG emissions from electric utility generating units~~2014, ~~demand~~RGGI ~~for~~states ~~coal~~implemented ~~will likely be further decreased. The EPA also issued~~ a ~~final rule for~~ new ~~coal-fired~~CO2 ~~power~~cap ~~plants~~of in91 ~~August~~million ~~2015~~short tons, which ~~essentially~~declined ~~set performance standards for coal-fired power plants that requires partial carbon capture and sequestration (“CCS”)~~2. ~~Additional~~5 ~~legal~~percent ~~challenges~~each ~~have~~year ~~been~~from ~~filed~~2015 ~~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~~2020. InIt ~~addition,~~is ~~passage~~likely 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 wethese ~~mine~~regional ~~and~~efforts ~~sell,~~will ~~thereby reducing our revenues and materially and adversely affecting our business and results of operations~~continue.

~~Many~~The ~~states~~Western ~~and~~Regional ~~regions~~Climate ~~have~~Action ~~adopted~~Initiative ~~greenhouse~~(“WCI”) ~~gas~~seeks ~~initiatives~~to ~~and~~identify, ~~certain~~evaluate ~~governmental~~and ~~bodies~~implement ~~have~~collective orand ~~are considering the imposition~~cooperative ofmethods ~~fees or taxes based on the emission~~ of reducing greenhouse gases byin ~~certain~~the ~~facilities,~~subject ~~including~~regions ~~coal-fired~~to ~~electric~~15% ~~generating~~below ~~facilities. For example, in~~ 2005, ~~ten~~levels ~~northeastern~~by ~~states~~2020. ~~entered~~The ~~into~~participants ~~the~~consist ~~Regional~~of ~~Greenhouse Gas Initiative agreement (“RGGI”)~~California ~~calling~~and ~~for~~two ~~implementation~~Canadian ofprovinces: aNova ~~cap~~Scotia and ~~trade~~Quebec. ~~program~~Additionally, ~~aimed~~in atOctober ~~reducing~~2019, ~~carbon~~California ~~dioxide~~and ~~emissions~~Quebec ~~from~~entered ~~power~~into ~~plants~~a ~~in the participating~~cap-and-trade ~~states~~agreement. The ~~members~~Department of ~~RGGI~~Justice ~~have~~then ~~established~~filed insuit ~~statute~~against ~~and/or~~California ~~regulation~~over aits ~~carbon~~agreement ~~dioxide~~with ~~trading program~~Quebec. ~~Auctions~~That ~~for~~litigation ~~carbon~~is ongoing. ~~dioxide~~If ~~allowances under~~ the ~~program~~agreement ~~began~~is inupheld, ~~September~~and ~~2008.~~the ~~Though~~cap-and-trade ~~New~~agreement ~~Jersey~~stays ~~withdrew from RGGI~~ in ~~2011~~place, ~~since~~demand ~~its~~for ~~inception, several~~coal-fired ~~additional~~power ~~northeastern~~may ~~states and Canadian provinces have joined as participants or observers~~decrease.

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

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

If mandatory restrictions on CO2 emissions are imposed, the ability to capture and store large volumes of carbon dioxide emissions from coal-fired power plants may be a key mitigation technology to achieve emissions reductions while meeting projected energy demands. A number of recent legislative and regulatory initiatives to encourage the development and use of carbon capture and storage technology have been proposed or enacted. For example, in October 2015, the EPA released a rule that established, for the first time, new source performance standards under the federal Clean Air Act for CO2 emissions from new fossil fuel-fired electric utility generating power plants. The EPA has designated partial carbon capture and sequestration as the best system of emission reduction for newly constructed fossil fuel-fired steam generating units at power plants to employ to meet the standard. However, widespread cost-effective deployment of CCS will occur only if the technology is commercially available at economically competitive prices and supportive national policy frameworks are in place.17

18If mandatory restrictions on CO2 emissions are imposed, the ability to capture and store large volumes of carbon dioxide emissions from coal-fired power plants may be a key mitigation technology to achieve emissions reductions while meeting projected energy demands. A number of legislative and regulatory initiatives to encourage the development and use of carbon capture and storage technology have been proposed or enacted. For example, in October 2015, the EPA released a rule that established, for the first time, new source performance standards under the federal Clean Air Act for CO2 emissions from new fossil fuel-fired electric utility generating power plants. The EPA has designated partial carbon capture and sequestration as the best system of emission reduction for newly constructed fossil fuel-fired steam generating units at power plants to employ to meet the standard. In December 2018, EPA proposed a rule amending its prior determination that carbon capture and sequestration is the best system of emission reduction. However, if that rule is not finalized, or if other legal actions require fossil fuel-fired power plants to use carbon capture and storage technology, the demand for coal may decrease. However, widespread cost-effective deployment of CCS will occur only if the technology is commercially available at economically competitive prices and supportive national policy frameworks are in place.

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

These and other current or future global climate change laws, regulations, court orders or other legally enforceable mechanisms, or related public perceptions regarding climate change, are expected to require additional controls on coal-fired power plants and industrial boilers and may cause some users of coal to further switch from coal to alternative sources of fuel, thereby depressing demand and pricing for coal.

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

Clean Water Act

The Federal Clean Water Act (the “CWA”) and similar state and local laws and regulations affect coal mining operations by imposing restrictions on the discharge of pollutants, including dredged or fill material, into waters of the U.S. The CWA establishes in-stream water quality and treatment standards for wastewater discharges that are applied to wastewater dischargers through Section 402 National Pollutant Discharge Elimination System (“NPDES”) permits. Regular monitoring, as well as compliance with reporting requirements and performance standards, are preconditions for the issuance and renewal of Section 402 NPDES permits. Individual permits or general permits under Section 404 of the CWA are required to discharge dredged or fill materials into waters of the U.S. including wetlands, streams, and other areas meeting the regulatory definition. Expansion of EPA jurisdiction over these areas has the potential to adversely impact our operations. ~~Considerable~~Legal ~~legal~~ uncertainty exists surrounding the standard for what constitutes jurisdictional waters and wetlands subject to the protections and requirements of the Clean Water Act. A In 2015, ~~rulemaking~~EPA byissued ~~EPA~~a rule to ~~revise~~expand the ~~standard~~definition ~~was stayed nationwide by the U.S. Court of Appeals~~ for ~~the~~what ~~Sixth~~constitutes ~~Circuit~~jurisdictional waters and ~~stayed for certain primarily western states by a United States District Court in North Dakota~~wetlands. InThat ~~January~~rule ~~2018~~was challenged, ~~the~~and ~~Supreme~~courts ~~Court determined~~stayed ~~that~~ the ~~circuit courts do not have jurisdiction to hear challenges to the 2015~~ rule,’s ~~removing~~implementation ~~the~~in ~~basis~~many ~~for the Sixth Circuit to continue its nationwide stay~~states. In ~~February~~October ~~2018~~2019, ~~the~~ EPA and the U.S. Army Corps of Engineers (the “Corps”) ~~published~~ arepealed ~~final rule extending~~ the ~~applicability date of the~~ 2015 rule ~~such that the rule would not be applicable until February 2020~~. In ~~August~~Challenges 2018, the U.S. District Court for the District of South Carolina invalidated the two-year nationwide delay of the rule, leaving the 2015 rule in effect in 26 states, while the pre-2015 regulations and guidance continue to ~~apply in 24 states. In December 2018,~~ the ~~EPA~~2019 ~~and~~repeal ~~the~~have ~~Corps~~been ~~proposed a new definition of “waters of the United States~~filed.” ~~Judicial~~Should ~~challenges to~~ the ~~2015~~ ~~rulemaking~~2019 ~~are likely to continue to work their way through the courts along with challenges to the more recent rulemaking extending the applicability date of the 2015 rule. The agencies’ efforts to~~ repeal ~~the 2015 rule and to revise the definition of “waters of the United States” will also likely~~ be ~~subject~~vacated ~~to lengthy judicial challenges. For now, EPA~~ and the ~~Corps~~ ~~are complying with the South Carolina District Court’s order in the 26 states in which it applies. Should the~~ 2015 rule be enforced in the states in which we operate, or should a different rule expanding the definition of ~~what~~waters ~~constitutes a water~~ of the United States be finalized ~~as a result of EPA and the Corps’s rulemaking process~~, we could face increased costs and delays with respect to obtaining permits for dredge and fill activities in wetland areas.

Our surface coal mining and preparation plant operations typically require such permits to authorize activities such as the creation of slurry ponds, stream impoundments, and valley fills. The EPA, or a state that has been delegated such authority by the EPA, issues NPDES permits for the discharge of pollutants into navigable waters, while the U.S. Army Corps of Engineers (the “Corps”) issues dredge and fill permits under Section 404 of the CWA. Where Section 402 NPDES permitting authority has been delegated to a state, the EPA retains a limited oversight role. The CWA also gives the EPA an oversight role in the Section 404 permitting program, including drafting substantive rules governing permit issuance by the Corps, providing comments on proposed permits, and, in some cases, exercising the authority to delay or pre-empt Corps issuance of a Section 404 permit. The EPA has recently asserted these authorities more forcefully to question, delay, and prevent issuance of some Section 402 and 404 permits for surface coal mining in Appalachia. Currently, significant uncertainty exists regarding the obtaining of permits under the CWA for coal mining operations in Appalachia due to various initiatives launched by the EPA regarding these permits.

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

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

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

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

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

2019

Hazardous Substances and Wastes

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

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

In 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~~CCR, though it defers a final Bevill regulatory determination with respect to ~~CCB~~CCR that is disposed of in landfills or surface impoundments. However, the D.C. Circuit vacated portions of the rule other than the Subtitle D decision. Other portions of the rule are also subject to legal uncertainty due to ongoing regulatory and judicial processes. Additionally, in December 2016, Congress passed the Water Infrastructure Improvements for the Nation Act, which provides for the establishment of state and EPA permit programs for the control of coal combustion residuals and authorizes states to incorporate EPA’s final rule for coal combustion residuals or develop other criteria that are at least as protective as the final rule. The costs of complying with these new requirements may result in a material adverse effect on our business, financial condition or results of operations, and could potentially increase our customers’ operating costs, thereby reducing their ability to purchase coal as a result. In addition, contamination caused by the past disposal of ~~CCB~~CCR, including coal ash, can lead to material liability to our customers under RCRA or other federal or state laws and potentially reduce the demand for coal.

Endangered Species Act

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

Use of Explosives

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

The storage of explosives is also subject to regulatory requirements. For example, pursuant to a rule issued by the Department of Homeland Security in 2007, facilities in possession of chemicals of interest (including ammonium nitrate at certain threshold levels) are required to complete a screening review in order to help determine whether there is a high level of security risk, such that a security vulnerability assessment and a site security plan will be required. It is possible that our use of explosives in connection with blasting operations may subject us to the Department of Homeland Security’s chemical facility security regulatory program. The costs of compliance with these requirements should not have a material adverse effect on our business, financial condition or results of operations.

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

Other Environmental and Mine Safety Laws

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

Federal Power Act – Grid Reliability Proposal

Pursuant to a direction from the Secretary of the Department of Energy, the Federal Energy Regulatory Commission (“FERC”) issued a notice of proposed rulemaking under the Federal Power Act regarding the valuation by regional electric grid system operators of the reliability and resilience attributes of electricity generation. The rulemaking would have required the FERC to impose market rules that would allow certain cost recovery by electricity-generating units that maintain a 90-day fuel supply on-site and that are therefore capable of providing electricity during supply disruptions from emergencies, extreme weather or natural or man-made disasters. Many coal-fired electricity generating plants could have qualified under this criteria and the cost recovery could have helped improve the economics of their operations. However, in January 2018, the FERC terminated the proposed rulemaking, finding that it failed to satisfy the legal requirements of section 206 of the Federal Power Act, and initiated a new proceeding to further evaluate whether additional FERC action regarding resilience is appropriate. Should a version of this rule be adopted in the future along the lines originally proposed, it could provide economic incentives for companies that produce electricity from coal, among other fuels, which could either slow or stabilize the trend in the shuttering of coal-fired power plants and could thereby maintain certain levels of domestic demand for coal. We cannot speculate on the timing or nature of any subsequent FERC or grid operator actions resulting from the FERC’s decision to further study the issue of grid resiliency.

Employees

To carry out our operations, our general partner and our subsidiaries employed ~~701~~605 full-time employees as of December 31, ~~2018~~2019. None of the employees are subject to collective bargaining agreements. We believe that we have good relations with these employees and since our inception we have had no history of work stoppages or union organizing campaigns.

Available Information

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

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 SEC’s website, http://www.sec.gov, contains reports, proxy and information statements, and other information regarding issuers, including us, that file electronically with the SEC.

Item 1A. Risk Factors.

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

Risks Inherent in Our Business

Beginning in the later part of the third quarter of 2019, we have experienced significantly weaker market demand and have seen prices move lower for the qualities of met and steam coal we produce. This downward price trend has been exacerbated by the recent coronavirus pandemic. In response to this reduced demand and to the significant health threats to our employees, on March 20, 2020, we temporarily idled production at several of our mines. See “—Our results of operations will be negatively impacted by the coronavirus pandemic.”

If we continue to experience weak demand and prices continue to lower for our met and steam coal, we may not be able to continue to give the required representations or meet all of the covenants and restrictions included in our Financing Agreement. If we violate any of the covenants or restrictions in our Financing Agreement, including the fixed-charge coverage ratio, some or all of our indebtedness may become immediately due and payable, and our Lenders may not be willing to make any loans under the additional commitment available under our Financing Agreement. If we are unable to give a required representation or we violate a covenant or restriction, then we will need a waiver from our Lenders under our Financing Agreement, or they may declare an event of default and, after applicable specified cure periods, all amounts outstanding under the Financing Agreement would become immediately due and payable. Although we believe our Lenders are well secured under the terms of our Financing Agreement, there is no assurance that the Lenders would agree to any such waiver. Failure to obtain financing or to generate sufficient cash flow from operations could cause us to further curtail our operations and reduce spending and alter our business plan. We may also be required to consider other options are currently considering alternatives to address our liquidity and balance sheet issues, such as selling additional assets or seeking merger opportunities, and depending on the urgency of our liquidity constraints, we may be required to pursue such an option at an inopportune time.

As of December 31, 2019, we are unable to demonstrate that we have sufficient liquidity to operate our business over the next twelve months and thus substantial doubt is raised about our ability to continue as a going concern. Accordingly, our independent registered public accounting firm has included an emphasis paragraph with respect to our ability to continue as a going concern in its report on our consolidated financial statements for the year ended December 31, 2019. The presence of the going concern emphasis paragraph in our auditors’ report may have an adverse impact on our relationship with third parties with whom we do business, including our customers, vendors, lenders and employees, and may make it difficult to raise additional debt financing to the extent needed to conduct normal operations. As a result, our business, results of operations, financial condition and prospects could be materially adversely affected.

Our results of operations will be negatively impacted by the coronavirus pandemic.

To date, the current and anticipated economic impact of the coronavirus pandemic, including the actions of governments and countries here in the United States and around the world designed to decrease the spread of the virus, have caused significant declines in demand for met and steam coal. In response to this reduced demand and to the significant health threats to our employees, on March 20, 2020, we temporarily idled production at several of our mines. We will continue to monitor conditions to ensure the health and welfare of our employees. We do not expect the idling of the coal production activities will affect our ability to fulfill current customer commitments, as loading and shipping crews will remain in place to ship coal from existing inventories.

If the impact of the coronavirus outbreak, including the significant decrease in economic activity, continue for an extended period of time or worsen, it could further reduce the demand for met and steam coal, which would have a material adverse effect on our business, financial condition, cash flows and results of operations.

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

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

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

	●	the liquidity of our common units;

	●	the market price of our common units;

	●	our ability to issue additional securities or obtain financing;

	●	the number of institutional and other investors that will consider investing in our common units;

	●	the number of market makers in our common units;

	●	the availability of information concerning the trading prices and volume of our common units; and

	●	the number of broker-dealers willing to execute trades in our common units.

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

WeSince ~~may~~2014, ~~not~~we have not had sufficient cash to enable us to pay the minimum quarterly distribution on our common units following establishment of cash reserves and payment of costs and expenses, including reimbursement of expenses to our general partner.

WeThe ~~may not have sufficient cash each quarter to pay the full~~ amount of ~~our minimum quarterly distribution of $4.45 per unit, or $17.80 per unit per year, which will require us to have available~~ cash of approximately $58.6 million per quarter, or $234.2 million per year, based on the number of common and subordinated units outstanding as of December 31, 2018 and the general partner interest. The amount of cash we can distribute on our common and subordinated units principally depends upon the amount of cash we generate from our operations, which will fluctuate from quarter to quarter based on, among other things:

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

	●	the price at which we are able to sell coal, which is affected by the supply of and demand for domestic and foreign coal;

23● the level of our operating costs, including reimbursement of expenses to our general partner and its affiliates. Our partnership agreement does not set a limit on the amount of expenses for which our general partner and its affiliates may be reimbursed; ● the proximity to and capacity of transportation facilities; ● the price and availability of alternative fuels; ● the impact of future environmental and climate change regulations, including those impacting coal-fired power plants; ● the level of worldwide energy and steel consumption; ● prevailing economic and market conditions; ● difficulties in collecting our receivables because of credit or financial problems of customers;

● the level of our operating costs, including reimbursement of expenses to our general partner and its affiliates. Our partnership agreement does not set a limit on the amount of expenses for which our general partner and its affiliates may be reimbursed; ● the proximity to and capacity of transportation facilities; ● the price and availability of alternative fuels; ● the impact of future environmental and climate change regulations, including those impacting coal-fired power plants; ● the level of worldwide energy and steel consumption; ● prevailing economic and market conditions; ● difficulties in collecting our receivables because of credit or financial problems of customers; ● the effects of new or expanded health and safety regulations; ● domestic and foreign governmental regulation, including changes in governmental regulation of the mining industry, the electric utility industry or the steel industry; ● changes in tax laws; ● weather conditions; and ● force majeure.24

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

Beginning with the quarter ended September 30, 2014, distributions on our common units were below the minimum level and, beginning with the quarter ended June 30, 2015, we suspended the quarterly distribution on our common units altogether. Pursuant to our partnership agreement, our common units accrue arrearages every quarter when the distribution level is below the minimum quarterly distribution level and our subordinated units do not accrue such arrearages. Thus, we have arrearages accumulating on our common units since the distribution level has been below our minimum quarterly level of $4.45 per unit. We do not expect to pay distributions on our common or subordinated units in the foreseeable future.

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

Our results of operations and the value of our coal reserves are significantly dependent upon the prices we receive for our coal as well as our ability to improve productivity and control costs. Prices for coal tend to be cyclical. The prices we receive for coal depend upon factors beyond our control, including:

●

the supply of domestic and foreign coal;

	●	the demand for domestic and foreign coal, which is significantly affected by the level of consumption of steam coal by electric utilities and the level of consumption of metallurgical coal by steel producers;

	●	the price and availability of alternative fuels for electricity generation;

	●	the proximity to, and capacity of, transportation facilities;

	●	domestic and foreign governmental regulations, particularly those relating to the environment, climate change, health and safety;

	●	the level of domestic and foreign taxes;

	●	weather conditions;

	●	terrorist attacks and the global and domestic repercussions from terrorist activities; and

	●	prevailing economic conditions.

Any adverse change in these factors could result in weaker demand and lower prices for our products. In addition, global financial and credit market disruptions have historically had an impact on the coal industry generally and may continue to do so. The demand for electricity and steel may decline if economic conditions weaken. If electricity and steel demand weaken, we may not be able to sell all of the coal we are capable of producing or sell our coal at acceptable prices.

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

We performed a comprehensive review of our coal mining operation as well as potential future development projects for the year ended December 31, 2018 to ascertain any potential impairment losses. We did not record any impairment losses for coal properties, mine development costs or coal mining equipment and related facilities for the year ended December 31, 2018.

We performed a comprehensive review of our current coal mining operation as well as potential future development projects for the year ended December 31, 2017 to ascertain any potential impairment losses. We engaged an independent third party to perform a fair market value appraisal on certain parcels of land that we own in Mesa County, Colorado. The parcels appraised for $6.0 million compared to the carrying value of $6.8 million. We recorded an impairment loss of $0.8 million, which is recorded on the Asset impairment and related charges line of the consolidated statements of operations and comprehensive income. No other coal properties, mine development costs or other coal mining equipment and related facilities were impaired as of December 31, 2017.

We also recorded an impairment charge of $21.8 million related to the call option received from a third party to acquire substantially all of the outstanding common stock of Armstrong Energy, Inc. On October 31, 2017, Armstrong Energy filed Chapter 11 petitions in the Eastern District of Missouri’s United States Bankruptcy Court. Per the Chapter 11 petitions, Armstrong Energy filed a detailed restructuring plan as part of the Chapter 11 proceedings. On February 9, 2018, the U.S. Bankruptcy Court confirmed Armstrong Energy’s Chapter 11 reorganization plan and as such we concluded that the call option had no carrying value. An impairment charge of $21.8 million related to the call option was recorded on the Asset impairment and related charges line of the consolidated statements of operations and comprehensive income.

We performed a comprehensive review of our current coal mining operations as well as potential future development projects to ascertain any potential impairment losses during 2019. We identified two properties that were potentially impaired based upon changes in market conditions, financing alternatives or other factors, specifically at our Rhino Eastern and Taylorville Mining undeveloped properties where market conditions related to any future development deteriorated in the fourth quarter of 2019. We recorded approximately $26.0 million of total asset impairment and related charges related to these undeveloped properties for the year ended December 31, 2019, which is recorded on the Asset impairment and related charges line of the consolidated statements of operations. The $26.0 million impairment included $17.9 million impairment related to future development of Rhino Eastern and an $8.1 million impairment related to future development of Taylorville Mining LLC

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

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

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

Steam coal accounted for approximately 8182% of our coal sales volume for the year ended December 31, ~~2018~~2019. The majority of our sales of steam coal during this period were to electric utilities for use primarily as fuel for domestic electricity consumption. The amount of coal consumed by the domestic electric utility industry is affected primarily by the overall demand for electricity, environmental and other governmental regulations, and the price and availability of competing fuels for power plants such as nuclear, natural gas and oil as well as alternative sources of energy. We compete generally with producers of other fuels, such as natural gas and oil. A decline in price for these fuels could cause demand for coal to decrease and adversely affect the price of our coal. For example, sustained low natural gas prices have led, ~~in some instances,~~ to decreased coal consumption by several domestic electricity-generating utilities. According to the EIA, in 2018, coal accounted for approximately 27% of domestic electricity generation. If alternative energy sources, such as nuclear, hydroelectric, wind or solar, continue to become more cost-competitive on an overall basis, demand for coal could decrease further and the price of coal could be materially and adversely affected. Further, legislation requiring, subsidizing or providing tax benefits for the use of alternative energy sources and fuels, or legislation providing financing or incentives to encourage continuing technological advances in this area, could further enable alternative energy sources to become more competitive with coal. A decrease in coal consumption by the domestic electric utility industry could adversely affect the price of coal, which could materially adversely affect our results of operations and cash available for distribution to our unitholders.

Numerous political and regulatory authorities, along with environmental activist groups, are devoting substantial resources to anti-coal activities to minimize or eliminate the use of coal as a source of electricity generation, domestically and internationally, thereby further reducing the demand and pricing for coal, and potentially materially and adversely impacting our future financial results, liquidity and growth prospects.

Concerns about the environmental impacts of coal combustion, including perceived impacts on global climate issues, are resulting in increased regulation of coal combustion in many jurisdictions, unfavorable lending policies by government-backed lending institutions and development banks toward the financing of new overseas coal-fueled power plants and divestment efforts affecting the investment community, which could significantly affect demand for our products or our securities. Global climate issues continue to attract public and scientific attention. Numerous reports, such as the Fourth and Fifth Assessment Report of the Intergovernmental Panel on Climate Change, have also engendered concern about the impacts of human activity, especially fossil fuel combustion, on global climate issues. In turn, increasing government attention is being paid to global climate issues and to emissions of GHGs, including emissions of carbon dioxide from coal combustion by power plants. The 2015 Paris climate summit agreement resulted in voluntary commitments by numerous countries to reduce their GHG emissions, and could result in additional firm commitments by various nations with respect to future GHG emissions. These commitments could further disfavor coal-fired generation, particularly in the medium- to long-term.

Enactment of laws or passage of regulations regarding emissions from the combustion of coal by the United States, some of its states or other countries, or other actions to limit such emissions, could also result in electricity generators further switching from coal to other fuel sources or additional coal-fueled power plant closures. Further, policies limiting available financing for the development of new coal-fueled power plants could adversely impact the global demand for coal in the future.

There have also been efforts in recent years affecting the investment community, including investment advisors, sovereign wealth funds, public pension funds, universities and other groups, promoting the divestment of fossil fuel equities and also pressuring lenders to limit funding to companies engaged in the extraction of fossil fuel reserves. In California, for example, ~~legislation was signed into law~~ in ~~October~~2017 ~~2015 that requires~~ California’s state pension funds todivested ~~divest~~from ~~investments in~~ companies that generate 50% or more of their revenue from coal mining by July 2017 pursuant to state legislation. More recently, in December 2017, the Governor of New York announced that the New York Common Fund will immediately cease all new investments in entities with “significant fossil fuel activities,” and the World Bank announced that it will no longer finance upstream oil and gas after 2019, except in “exceptional circumstances.” Other activist campaigns have urged banks to cease financing coal-driven businesses. As a result, numerous major banks have enacted such policies. The impact of such efforts may adversely affect the demand for and price of securities issued by us, and impact our access to the capital and financial markets.

In addition, several well-funded non-governmental organizations have explicitly undertaken campaigns to minimize or eliminate the use of coal as a source of electricity generation. For example, the goals of Sierra Club’s “Beyond Coal” campaign include retiring one-third of the nation’s coal-fired power plants by 2020, replacing retired coal plants with “clean energy solutions,” and “keeping coal in the ground.”

The net effect of these developments is to make it more costly and difficult to maintain our business and to continue to depress demand and pricing for our coal. A substantial or extended decline in the prices we receive for our coal due to these or other factors could further reduce our revenue and profitability, cash flows, liquidity, and value of our coal reserves and result in losses.

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

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

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

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

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

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

	●	sealing off abandoned areas of underground coal mines;

	●	mine safety equipment, training and emergency reporting requirements;

	●	substantially increased civil penalties for regulatory violations;

	●	training and availability of mine rescue teams;

	●	underground “refuge alternatives” capable of sustaining trapped miners in the event of an emergency;

	●	flame-resistant conveyor belt, fire prevention and detection, and use of air from the belt entry; and

	●	post-accident two-way communications and electronic tracking systems.

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

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

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

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

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

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

Numerous governmental permits and approvals are required for mining operations, and we can face delays, challenges to, and difficulties in acquiring, maintaining or renewing necessary permits and approvals, including environmental permits. The permitting rules, and the interpretations of these rules, are complex, change frequently, and are often subject to discretionary interpretations by regulators, all of which may make compliance more difficult or impractical, and may possibly preclude the continuance of ongoing mining operations or the development of future mining operations. In addition, the public has certain statutory rights to comment upon and otherwise impact the permitting process, including through court intervention. Over the past few years, the length of time needed to bring a new surface mine into production has increased because of the increased time required to obtain necessary permits. The slowing pace at which permits are issued or renewed for new and existing mines has materially impacted production in Appalachia, but could also affect other regions in the future.

Section 402 National Pollutant Discharge Elimination System permits and Section 404 CWA permits are required to discharge wastewater and discharge dredged or fill material into waters of the United States (“WOTUS”). Expansion of EPA jurisdiction over these areas has the potential to adversely impact our operations. Considerable legal uncertainty exists surrounding the standard for what constitutes jurisdictional waters and wetlands subject to the protections and requirements of the Clean Water Act. Please read “Part I, Item 1. Business—Regulation and Laws—Clean Water Act.” Currently, 26 states are subject to the 2015 rule, while the pre-2015 regulations and guidance continue to apply in 24 states. Should the 2015 rule be enforced in the states in which we operate, or should a different rule expanding the definition of what constitutes a water of the United States be finalized as a result of EPA and the Corps’s rulemaking process, we could face increased costs and delays with respect to obtaining permits for dredge and fill activities in wetland areas. Our surface coal mining operations typically require such permits to authorize such activities as the creation of slurry ponds, stream impoundments, and valley fills. Although the CWA gives the EPA a limited oversight role in the Section 404 permitting program, the EPA has recently asserted its authorities more forcefully to question, delay, and prevent issuance of some Section 404 permits for surface coal mining in Appalachia. Currently, significant uncertainty exists regarding the obtaining of permits under the CWA for coal mining operations in Appalachia due to various initiatives launched by the EPA regarding these permits.

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

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

These risks include:

●

unfavorable geologic conditions, such as the thickness of the coal deposits and the amount of rock embedded in or overlying the coal deposit;

	●	inability to acquire or maintain necessary permits or mining or surface rights;

	●	changes in governmental regulation of the mining industry or the electric utility industry;

	●	adverse weather conditions and natural disasters;

	●	accidental mine water flooding;

	●	labor-related interruptions;

	●	transportation delays;

	●	mining and processing equipment unavailability and failures and unexpected maintenance problems; and

	●	accidents, including fire and explosions from methane.

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

	●	quality of coal;

	●	geological and mining conditions and/or effects from prior mining that may not be fully identified by available exploration data or which may differ from our experience in areas where we currently mine;

	●	the percentage of coal in the ground ultimately recoverable;

	●	the assumed effects of regulation, including the issuance of required permits, taxes, including severance and excise taxes and royalties, and other payments to governmental agencies;

	●	historical production from the area compared with production from other similar producing areas;

	●	the timing for the development of reserves; and

	●	assumptions concerning equipment and productivity, future coal prices, operating costs, capital expenditures and development and reclamation costs.

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

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

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

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

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

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

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

For example, on the international level, the United States was 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; however, in August 2017 the U.S. State Department officially informed the United Nations of the intent of the U.S. to withdraw from the agreement, with the earliest possible effective date of withdrawal being November 4, 2020. Despite the planned withdrawal, certain U.S. city and state governments have announced their intention to satisfy their proportionate obligations under the Paris Agreement. These commitments could further reduce demand and prices for coal.

At the federal level, EPA has finalized a number of rules related to GHG emissions. For example, the EPA issued its final CPP rules ~~that~~setting ~~establish~~ carbon pollution standards for power plants~~, called CO2 emission performance rates~~. ~~Judicial~~The ~~challenges led the~~ U.S. Supreme Court tostayed ~~grant a stay of~~ the implementation of the CPP in February 2016. In ByJune ~~its terms~~2019, ~~this~~EPA ~~stay~~finalized ~~will remain in effect throughout~~ the ~~pendency~~proposed ofAffordable ~~the~~Clean ~~appeals~~Energy ~~process.~~(“ACE”) ~~The~~Rule ~~stay~~to ~~suspends~~replace the ~~rule~~CPP, ~~including~~provide ~~the requirement that~~ states ~~submit~~with ~~their~~authority ~~initial plans by September 2016. The Supreme Court’s stay applies only~~ to ~~EPA’s~~regulate ~~regulations~~GHGs ~~for CO2 emissions~~ from ~~existing~~coal-fired power plants, and ~~will~~establish ~~not~~heat ~~affect~~rate ~~EPA’s~~improvements ~~standards~~as ~~for new power plants. It is not yet clear how~~ the ~~courts~~ ~~will~~best ~~rule~~system ~~on the legality~~ of ~~the CPP~~emissions reduction. ~~Additionally,~~The inACE ~~October~~rule ~~2017~~has ~~EPA~~been ~~proposed~~challenged toin ~~repeal~~court ~~the~~and ~~CPP, although~~ the final outcome of ~~this~~that ~~action and the pending~~ litigation ~~regarding the CPP~~ is uncertain ~~at this time~~. InIf ~~connection with~~ the ~~proposed repeal,~~ACE ~~EPA~~Rule ~~issued an Advance Notice of Proposed Rulemaking (“ANPRM”)~~ results in ~~December~~state ~~2017~~plans ~~regarding~~to ~~emission~~reduce ~~guidelines to~~the ~~limit~~level of GHG emissions from ~~existing~~electric ~~electricity~~ utility generating units~~. In August 2018~~, the EPA issued the proposed ACE Rule, which would replace the CPP. If the ACE Rule is finalized, it will likely be subject to judicial challenge. If the effort to repeal and replace the CPP is unsuccessful and the rules were upheld at the conclusion of the appellate process and were implemented in their current form, or if ~~the~~EPA ~~ACE~~implements ~~Rule~~more ~~results~~stringent regulations in ~~state plans to reduce~~ the ~~level of GHG emissions from electric utility generating units~~future, 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. ~~Additional~~ ~~legal~~In ~~challenges~~December ~~have~~2018, ~~been~~EPA ~~filed~~proposed ~~against~~a ~~the~~rule ~~EPA’s~~amending ~~rules~~its ~~for~~prior ~~new~~determination ~~power~~that ~~plants.~~carbon ~~The~~capture ~~EPA’s~~and ~~GHG~~sequestration is ~~rules~~the ~~for new~~best ~~and~~system ~~existing~~of ~~power~~emission ~~plants~~reduction. However, ~~taken~~if ~~together~~that rule is not finalized, ~~have~~or ~~the~~if ~~potential~~other legal actions require fossil fuel-fired power plants to ~~severely~~use ~~reduce~~of carbon capture and storage technology, the demand for coal may decrease. In addition, passage of any comprehensive federal climate change and energy legislation could impact the demand for coal. Any reduction in the amount of coal consumed by North American electric power generators could reduce the price of coal that we mine and sell, thereby reducing our revenues and materially and adversely affecting our business and results of operations.

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

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

If mandatory restrictions on carbon dioxide emissions are imposed, the ability to capture and store large volumes of carbon dioxide emissions from coal-fired power plants may be a key mitigation technology to achieve emissions reductions while meeting projected energy demands. A number of ~~recent~~ legislative and regulatory initiatives to encourage the development and use of CCS technology ~~have~~ have been proposed or enacted. For example, in October 2015, the EPA released a rule that established, for the first time, new ~~source~~ source performance standards under the federal Clean Air Act for CO2 emissions from new fossil fuel-fired electric ~~utility~~ utility generating power plants. The EPA has designated partial carbon capture and sequestration as the best system of emission ~~reduction~~ reduction for newly constructed fossil fuel-fired steam generating units at power plants to employ to meet the standard. ~~However~~In December 2018, EPA proposed a rule amending its prior determination that carbon capture and sequestration is the best system of emission reduction. If that rule is not finalized, or if other legal actions require fossil fuel-fired power plants to use of carbon capture and storage technology, the demand for coal may decrease. 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.

In the meantime, the EPA and other regulators are using existing laws, including the federal Clean Air Act, to limit emissions of carbon dioxide and other GHGs from major sources, including coal-fired power plants that may require the use of “best available control technology” or “BACT.” As state permitting authorities continue to consider GHG control requirements as part of major source permitting BACT requirements, costs associated with new facility permitting and use of coal could increase substantially. A growing concern is the possibility that BACT will be determined to be the use of an alternative fuel to coal.

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

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

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

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

	●	the lack of availability, higher expense or unreasonable terms of new surety bonds;

	●	the ability of current and future surety bond issuers to increase required collateral; and

	●	the exercise by third-party surety bond holders of their right to refuse to renew the surety bonds.

We maintain surety bonds with third parties for reclamation expenses and other miscellaneous obligations. It is possible that we may in the future have difficulty maintaining our surety bonds for mine reclamation. Due to adverse economic conditions and the volatility of the financial markets, surety bond providers may be less willing to provide us with surety bonds or maintain ~~existing~~ existing surety bonds or may demand terms that are less favorable to us than the terms we currently receive. We may have greater difficulty satisfying the liquidity requirements under our existing surety bond contracts. As of December 31, ~~2018~~2019, we had $4241.6 million in reclamation surety bonds, secured by $3.0 million in cash collateral held by our surety bond provider. Of the $4241.6 million, approximately $0.4 million relates to surety bonds for Deane Mining, LLC ~~and approximately $3.4 million relates to surety bonds for Sands Hill Mining~~, ~~LLC,~~ which ~~in each case~~ have not been transferred or replaced by the ~~buyers~~ buyer of Deane Mining, LLC ~~or Sands Hill Mining, LLC~~ as was agreed to by the parties as part of the ~~transactions~~transaction. We can provide no assurances that a surety company will underwrite the surety bonds of the ~~purchasers~~purchaser of ~~these entities~~Deane Mining LLC, nor are we aware of the actual amount of reclamation at any given time. Further, if there was a claim under these surety bonds prior to the transfer or replacement of such bonds by the buyer ~~buyers~~ of Deane Mining, ~~LLC~~ ~~or Sands Hill Mining,~~ LLC, ~~then~~ we may be responsible to the surety company for any amounts it pays in respect of such claim. While the ~~buyers~~buyer ~~are~~is required to indemnify us for damages, including reclamation liabilities, pursuant to the agreements governing the sales of ~~these~~this ~~entities~~entity, we may not be successful in obtaining any indemnity or any amounts received may be inadequate. ~~For more information, please read “Part I, Item 1. Business— Recent Developments—Letter of Credit Facility—PNC Bank.”~~ If we do not maintain sufficient borrowing capacity or have other resources to satisfy our surety and bonding requirements, our operations and cash available for distribution to our unitholders could be adversely affected.

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

We sell a material portion of our coal under supply contracts. As of December 31, ~~2018~~2019, we had sales commitments for approximately 7482% of our estimated coal production (including purchased coal to supplement our production) for the year ending December 31, ~~2019~~2020. When our current contracts with customers expire, our customers may decide not to extend or enter into new contracts. Of our total future committed tons, under the terms of the supply contracts, we will ship 6173% in ~~2019~~2020, 3317% in ~~2020~~2021, and 610% in ~~2021~~2022. We derived approximately 8073.52% of our total coal revenues from coal sales to our ten largest customers for the year ended December 31, ~~2018~~2019, with affiliates of our top three customers accounting for approximately 4038.43% of our coal revenues during that period.

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

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

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

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

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

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

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

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

If we sustain cyber-attacks or other security breaches that disrupt our operations, or that result in the unauthorized release of proprietary or confidential information, we could be exposed to significant liability, reputational harm, loss of revenue, increased costs or other risks.

We may be subject to security breaches which could result in unauthorized access to our facilities or to information we are trying to protect. Unauthorized physical access to one or more of our facilities or locations, or electronic access to our proprietary or confidential information could result in, among other things, unfavorable publicity, litigation by parties affected by such breach, disruptions to our operations, loss of customers, and financial obligations for damages related to the theft or misuse of such information, any of which could have a substantial impact on our results of operations, financial condition or cash flow.

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

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

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

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

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

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

	●	our ability to obtain additional financing, if necessary, for working capital, capital expenditures (including acquisitions) or other purposes may be impaired or such financing may not be available on favorable terms;

	●	covenants contained in our existing and future credit and debt arrangements will require us to meet financial tests that may affect our flexibility in planning for and reacting to changes in our business, including possible acquisition opportunities;

	●	we will need a portion of our cash flow to make principal and interest payments on our indebtedness, reducing the funds that would otherwise be available for operations, distributions to unitholders and future business opportunities;

	●	we may be more vulnerable to competitive pressures or a downturn in our business or the economy generally; and

	●	our flexibility in responding to changing business and economic conditions may be limited.

Increases in our total indebtedness would increase our total interest expense, which would in turn reduce our forecasted cash available for distribution. As of December 31, ~~2018~~2019 our current portion of long-term debt that will be funded from cash flows from operating activities during ~~2019~~2020 was approximately $25.23 million. Our ability to service our indebtedness will depend upon, among other things, our future financial and operating performance, which will be affected by prevailing economic conditions and financial, business, regulatory and other factors, some of which are beyond our control. If our operating results are not sufficient to service our current or future indebtedness, we will be forced to take actions such as reducing or delaying our business activities, acquisitions, investments and/or capital expenditures, selling assets, restructuring or refinancing our indebtedness, or seeking additional equity capital or bankruptcy protection. We may not be able to affect any of these remedies on satisfactory terms, or at all.

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

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

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

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

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

	●	failure to pay principal, interest or any other amount when due;

	●	breach of the representations or warranties in the credit agreement;

	●	failure to comply with the covenants in the credit agreement;

	●	cross-default to other indebtedness;

	●	bankruptcy or insolvency;

	●	failure to have adequate resources to maintain, and obtain, operating permits as necessary to conduct our operations substantially as contemplated by the mining plans used in preparing the financial projections; and

	●	a change of control.

Any subsequent refinancing of our current debt or any new debt could have similar restrictions. Our ability to comply with the covenants and restrictions contained in our financing agreement may be affected by events beyond our control, including prevailing economic, financial and industry conditions. If market or other economic conditions deteriorate, our ability to comply with these covenants may be impaired. If we violate any of the restrictions, covenants, ratios or tests in our credit agreement, a significant portion of our indebtedness may become immediately due and payable, and our lenders’ commitment to make further loans to us may terminate. We might not have, or be able to obtain, sufficient funds to make these accelerated payments. In addition, our obligations under our ~~credit~~financing agreement will be secured by substantially all of our assets, and if we are unable to repay our indebtedness under our financing agreement, the lenders could seek to foreclose on such assets. For more information, please read “Part I, Item 1. Business—Recent Developments—Financing Agreement.”

Our business is subject to cybersecurity risks.

As is typical of modern businesses, we are reliant on the continuous and uninterrupted operation of its information technology (“IT”) systems. User access of our sites and IT systems can be critical elements to our operations, as is cloud security and protection against cyber security incidents. Any IT failure pertaining to availability, access or system security could potentially result in disruption of our activities, and could adversely affect our reputation, operations or financial performance.

Potential risks to the our IT systems could include unauthorized attempts to extract business sensitive, confidential or personal information, denial of access extortion, corruption of information or disruption of business processes, or by inadvertent or intentional actions by the our employees or vendors. A cybersecurity incident resulting in a security breach or failure to identify a security threat could disrupt business and could result in the loss of sensitive, confidential information or other assets, as well as litigation, regulatory enforcement, violation of privacy or securities laws and regulations, and remediation costs, all of which could materially impact the our business or reputation.

Risks Inherent in an Investment in Us

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

Royal owns and controls our general partner. Although our general partner has a fiduciary duty to manage us in a manner beneficial to us and our unitholders, the executive officers and directors of our general partner have a fiduciary duty to manage our general partner in a manner beneficial to its owners. Therefore, conflicts of interest may arise between its owners and our general partner, on the one hand, and us and our unitholders, on the other hand. In resolving these conflicts of interest, our general partner may favor its own interests and the interests of its owners over the interests of our common unitholders. These conflicts include the following situations:

● our general partner is allowed to take into account the interests of parties other than us, such as its owners, in resolving conflicts of interest, which has the effect of limiting its fiduciary duty to our unitholders; ● neither our partnership agreement nor any other agreement requires Royal to pursue a business strategy that favors us; ● our partnership agreement limits the liability of and reduces fiduciary duties owed by our general partner and also restricts the remedies available to unitholders for actions that, without the limitations, might constitute breaches of fiduciary duty; ● except in limited circumstances, our general partner has the power and authority to conduct our business without unitholder approval; ● our general partner determines the amount and timing of asset purchases and sales, borrowings, issuances of additional partnership securities and the level of reserves, each of which can affect the amount of cash that is distributed to our unitholders; ● our general partner determines the amount and timing of any capital expenditure and whether a capital expenditure is classified as a maintenance capital expenditure, which reduces operating surplus, or an expansion capital expenditure, which does not reduce operating surplus; ● our general partner may cause us to borrow funds in order to permit the payment of cash distributions, even if the purpose or effect of the borrowing is to make a distribution on the subordinated units, to make incentive distributions or to accelerate the expiration of the subordination period; ● our partnership agreement permits us to distribute up to $25.0 million as operating surplus, even if it is generated from asset sales, non-working capital borrowings or other sources that would otherwise constitute capital surplus. This cash may be used to fund distributions on our subordinated units or the incentive distribution rights; ● our general partner determines which costs incurred by it and its affiliates are reimbursable by us; ● our partnership agreement does not restrict our general partner from causing us to pay it or its affiliates for any services rendered to us or entering into additional contractual arrangements with its affiliates on our behalf; ● our general partner intends to limit its liability regarding our contractual and other obligations; ● our general partner may exercise its right to call and purchase common units if it and its affiliates own more than 80% of the common units;

● our partnership agreement permits us to distribute up to $25.0 million as operating surplus, even if it is generated from asset sales, non-working capital borrowings or other sources that would otherwise constitute capital surplus. This cash may be used to fund distributions on our subordinated units or the incentive distribution rights; ● our general partner determines which costs incurred by it and its affiliates are reimbursable by us; ● our partnership agreement does not restrict our general partner from causing us to pay it or its affiliates for any services rendered to us or entering into additional contractual arrangements with its affiliates on our behalf; ● our general partner intends to limit its liability regarding our contractual and other obligations; ● our general partner may exercise its right to call and purchase common units if it and its affiliates own more than 80% of the common units; ● our general partner controls the enforcement of obligations that it and its affiliates owe to us; ● our general partner decides whether to retain separate counsel, accountants or others to perform services for us; and ● our general partner may elect to cause us to issue common units to it in connection with a resetting of the target distribution levels related to our general partner’s incentive distribution rights without the approval of the conflicts committee of the board of directors of our general partner or the unitholders. This election may result in lower distributions to the common unitholders in certain situations.

In addition, Royal, its owners and entities in which they have an interest may compete with us. Please read “—Our sponsor, Royal and affiliates of our general partner may compete with us.”

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

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

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

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

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

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

In addition, because we distribute all of our available cash, our growth may not be as fast as that of businesses that reinvest their available cash to expand ongoing operations. To the extent we issue additional units in connection with any acquisitions or expansion capital expenditures, the payment of distributions on those additional units may increase the risk that we will be unable to maintain or increase our per unit distribution level. We may, in certain circumstances, be permitted under our partnership agreement and credit agreement to issue additional units, including units ranking senior to the common units. The incurrence of additional commercial borrowings or other debt to finance our growth strategy would result in increased interest expense, which, in turn, may impact the available cash that we have to distribute to our unitholders.

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

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

	●	how to allocate business opportunities among us and its affiliates;

	●	whether to exercise its limited call right;

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

	●	whether to exercise its registration rights;

	●	whether to elect to reset target distribution levels; and

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

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

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

Our partnership agreement contains provisions that restrict the remedies available to unitholders for actions taken by our general partner that might otherwise constitute breaches of fiduciary duty under state fiduciary duty law. For example, our partnership agreement:

● provides that whenever our general partner makes a determination or takes, or declines to take, any other action in its capacity as our general partner, our general partner is required to make such determination, or take or decline to take such other action, in good faith, and will not be subject to any other or different standard imposed by our partnership agreement, Delaware law, or any other law, rule or regulation, or at equity; ● provides that our general partner will not have any liability to us or our unitholders for decisions made in its capacity as a general partner so long as it acted in good faith, meaning that it believed that the decision was in the best interest of our partnership; ● provides that our general partner and its officers and directors will not be liable for monetary damages to us or our limited partners resulting from any act or omission unless there has been a final and non-appealable judgment entered by a court of competent jurisdiction determining that our general partner or its officers and directors, as the case may be, acted in bad faith or engaged in fraud or willful misconduct or, in the case of a criminal matter, acted with knowledge that the conduct was criminal; and

	●	provides that our general partner will not have any liability to us or our unitholders for decisions made in its capacity as a general partner so long as it acted in good faith, meaning that it believed that the decision was in the best interest of our partnership;

	●	provides that our general partner and its officers and directors will not be liable for monetary damages to us or our limited partners resulting from any act or omission unless there has been a final and non-appealable judgment entered by a court of competent jurisdiction determining that our general partner or its officers and directors, as the case may be, acted in bad faith or engaged in fraud or willful misconduct or, in the case of a criminal matter, acted with knowledge that the conduct was criminal; and

●

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

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

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

	(3)	on terms no less favorable to us than those generally being provided to or available from unrelated third parties; or

	(4)	fair and reasonable to us, taking into account the totality of the relationships among the parties involved, including other transactions that may be particularly favorable or advantageous to us.

In connection with a situation involving a transaction with an affiliate or a conflict of interest, any determination by our general partner must be made in good faith. If an affiliate transaction or the resolution of a conflict of interest is not approved by our common unitholders or the conflicts committee and the board of directors of our general partner determines that the resolution or course of action taken with respect to the affiliate transaction or conflict of interest satisfies either of the standards set forth in subclauses (3) and (4) above, then it will be presumed that, in making its decision, the board of directors acted in good faith, and in any proceeding brought by or on behalf of any limited partner or the partnership, the person bringing or prosecuting such proceeding will have the burden of overcoming such presumption.

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

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

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

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

Our general partner has the right, at any time when there are no subordinated units outstanding and it has received incentive distributions at the highest level to which it is entitled (48.0%) for each of the prior four consecutive fiscal quarters, to reset the initial target distribution levels at higher levels based on our distributions at the time of the exercise of the reset election. Following a reset election by our general partner, the minimum quarterly distribution will be adjusted to equal the reset minimum quarterly distribution and the target distribution levels will be reset to correspondingly higher levels based on percentage increases above the reset minimum quarterly distribution.

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

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

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

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

If our unitholders are dissatisfied with the performance of our general partner, they will have limited ability to remove our general partner. Unitholders are currently unable to remove our general partner without its consent because our general partner and its affiliates own sufficient units to be able to prevent its removal. The vote of the holders of at least 662/3% of all outstanding common and subordinated units voting together as a single class is required to remove our general partner. As of March 1520, ~~2019~~2020, Royal owned an aggregate of approximately 5253.90% of our common and subordinated units. Also, if our general partner is removed without cause during the subordination period and no units held by the holders of the subordinated units or their affiliates are voted in favor of that removal, all remaining subordinated units will automatically be converted into common units and any existing arrearages on the common units will be extinguished. Cause is narrowly defined in our partnership ~~agreement~~ agreement to mean that a court of competent jurisdiction has entered a final, non-appealable judgment finding our general partner ~~liable~~ liable for actual fraud or willful or wanton misconduct in its capacity as our general partner. Cause does not include most cases of of charges of poor management of the business.

Our general partner interest or the control of our general partner may be transferred to a third party without unitholder consent.

Our general partner may transfer its general partner interest to a third party in a merger or in a sale of all or substantially all of its assets without the consent of our unitholders. Furthermore, our partnership agreement does not restrict the ability of the members of our general partner to transfer their respective membership interests in our general partner to a third party. The new members of our general partner would then be in a position to replace the board of directors and executive officers of our general partner with their own designees and thereby exert significant control over the decisions taken by the board of directors and executive officers of our general partner. This effectively permits a “change of control” without the vote or consent of the unitholders.

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

If at any time our general partner and its affiliates own more than 80% of the common units, our general partner will have the right, but not the obligation, which it may assign to any of its affiliates or to us, to acquire all, but not less than all, of the common units held by unaffiliated persons at a price equal to the greater of (1) the average of the daily closing price of the common units over the 20 trading days preceding the date three days before notice of exercise of the call right is first mailed and (2) the highest per-unit price paid by our general partner or any of its affiliates for common units during the 90-day period preceding the date such notice is first mailed. As a result, unitholders may be required to sell their common units at an undesirable time or price and may not receive any return or a negative return on their investment. Unitholders may also incur a tax liability upon a sale of their units. Our general partner is not obligated to obtain a fairness opinion regarding the value of the common units to be repurchased by it upon exercise of the limited call right. There is no restriction in our partnership agreement that prevents our general partner from issuing additional common units and exercising its call right. If our general partner exercised its limited call right, the effect would be to take us private and, if the units were subsequently deregistered, we would no longer be subject to the reporting requirements of the Securities Exchange Act of 1934 (the “Exchange Act”). As of March 1520, ~~2019~~ 2020, Royal owned an aggregate of approximately 49.45% of our common units and approximately 93.23% of our subordinated units.

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

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

	●	our existing unitholders’ proportionate ownership interest in us will decrease;
	●	the amount of cash available for distribution on each unit may decrease;
	●	because a lower percentage of total outstanding units will be subordinated units, the risk that a shortfall in the payment of the minimum quarterly distribution will be borne by our common unitholders will increase;
	●	the ratio of taxable income to distributions may increase;
	●	the relative voting strength of each previously outstanding unit may be diminished; and
	●	the market price of the common units may decline.

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

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

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

●	an existing unitholder’s proportionate ownership interest in us will decrease;

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

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

●	the market price of the common units may decline.

In addition, to the extent the preferred units are converted into more than 66 2/3% of our common units, the holders of the preferred will have the right to remove our general partner.

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

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

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

As of March 1520, ~~2019~~2020, we had 13,~~098~~078,~~353~~668 common units, 1,143,~~686~~171 subordinated units and 1,500,000 Series A preferred units outstanding. All of the subordinated units will convert into common units on a one-for-one basis at the end of the subordination period. On March 21, 2016, we issued 6,000,000 common units to Royal in a private placement. In connection with this issuance, we entered into a registration rights agreement with Royal which grants Royal piggyback registration rights under certain circumstances ~~with~~ with respect to these common units. In addition, under our partnership agreement, our general partner and its affiliates (including Royal) have registration rights relating to the offer and sale of any units that they hold, subject to certain limitations. Sales by Royal or other large holders of a substantial number of our common units in the public markets, or the perception that such sales might occur, could have a material adverse effect on the price of our common units or could impair our ability to obtain capital through an offering of equity securities.

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

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

Cost reimbursements due to our general partner and its affiliates for services provided to us or on our behalf will reduce cash available for distribution to our unitholders. The amount and timing of such reimbursements will be determined by our general partner.

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

While our partnership agreement requires us to distribute all of our available cash, our partnership agreement, including provisions requiring us to make cash distributions contained therein, may be amended. Our partnership agreement generally may not be amended during the subordination period without the approval of our public common unitholders. However, our partnership agreement can be amended with the consent of our general partner and the approval of a majority of the outstanding common units (including common units held by Royal) after the subordination period has ended. As of March 1520, ~~2019,~~2020 Royal owned approximately 49.45% of the outstanding common units and 93.23% of our outstanding subordinated units.

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

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

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

Tax Risks to Common Unitholders

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

The anticipated after-tax economic benefit of an investment in our common units depends largely on our being treated as a partnership for U.S. federal income tax purposes. Despite the fact that we are organized as a limited partnership under Delaware law, we will be treated as a corporation for federal income tax purposes unless we satisfy a “qualifying income” requirement. Based on our current operations and current Treasury Regulations, we believe that we satisfy the qualifying income requirement and will be treated as a partnership. We have received a favorable private letter ruling from the IRS to the effect that, based on facts presented in the private letter ruling request, income from management fees, cost reimbursements and cost-sharing payments related to our management and operation of mining, production, processing, and sale of coal and from energy infrastructure support services will constitute “qualifying income” within the meaning of Section 7704 of the Internal Revenue Code of 1986 (the “Code”). We may, however, decide that it is in our best interest to be treated as a corporation for federal income tax purposes. Failing to meet the qualifying income requirement, a change in current law, or an election to be treated as a corporation, could cause us to be treated as a corporation for federal income tax purposes or otherwise subject us to taxation as an entity.

If we were treated as a corporation for U.S. federal income tax purposes, we would pay federal income tax on our taxable income at the corporate tax rate and would likely pay state and local income tax at varying rates. Any distributions to you would generally be taxed again as corporate distributions, and no income, gains, losses, deductions, or credits would flow through to you. Because a tax would be imposed upon us as a corporation, our cash available for distribution to our common unitholders would be substantially reduced. Therefore, treatment of us as a corporation would materially reduce the after-tax return to our common unitholders, likely causing a substantial reduction in the value of our common units.

Additionally, several states have been evaluating ways to subject partnerships to entity-level taxation through the imposition of state income, franchise, or other forms of taxation. We currently own assets and conduct business in several states that impose a margin or franchise tax. In the future, we may expand our operations to other states. Imposition of a similar tax on us in jurisdictions to which we expand could substantially reduce our cash available for distribution to our common unitholders. Our partnership agreement provides that if a law is enacted or existing law is modified or interpreted in a manner that subjects us to additional amounts of entity level taxation for U.S. federal, state, local, or foreign income tax purposes, the minimum quarterly distribution amount and the target distribution amounts may be adjusted to reflect the impact of that law or interpretation on us. Changes in current state law may subject us to additional entity level taxation by individual states.

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

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

The tax treatment of publicly traded partnerships or an investment in our common units could be subject to potential legislative, judicial or administrative changes and differing interpretations, possibly on a retroactive basis.

The present U.S. federal income tax treatment of publicly traded partnerships, including us, or an investment in our common units may be modified by administrative, legislative or judicial changes or differing interpretations at any time. For example, from time to time, members of Congress propose and consider substantive changes to the existing federal income tax laws that would affect publicly traded partnerships, including aelimination ~~prior~~of ~~legislative~~partnership ~~proposal~~tax ~~would~~treatment ~~have~~for ~~eliminated~~publicly traded partnerships. For example, the ~~qualifying~~“Clean ~~income~~Energy ~~exception~~ for America Act,” which is similar to legislation that was commonly proposed during the Obama ~~treatment~~Administration, ofwas ~~all~~introduced ~~publicly~~in ~~traded~~the ~~partnerships~~Senate ason ~~corporations~~May 2, 2019. If enacted, this proposal would, among other things, repeal the qualifying income exception within Section 7704(d)(1)(E) of the Code upon which we rely for our treatment as a partnership ~~for~~ for U.S. federal income tax purposes. In addition, the Treasury Department has issued, and in the future may issue, regulations ~~interpreting~~ interpreting those laws that affect publicly traded partnerships. ~~Although~~There ~~there are no current legislative or administrative proposals, there~~ can be no assurance that there will not be further changes to U.S. federal income tax laws or the Treasury Department’s interpretation of the qualifying income rules in a manner that could impact our ability to qualify as a publicly traded partnership in the future.

Any modification to the U.S. federal income tax laws may be applied retroactively and could make it more difficult or impossible for us to meet the exception for certain publicly traded partnerships to be treated as partnerships for U.S. federal income tax purposes. We are unable to predict whether any of these changes or other proposals will ultimately be enacted. Any such changes could negatively impact the value of an investment in our common units. You are urged to consult with your own tax advisor with respect to the status of regulatory or administrative developments and proposals and their potential effect on your investment in our common units.

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

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

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

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

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

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

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

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

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

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

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

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

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

Common unitholders may be subject to limitation on their ability to deduct interest expense incurred by us.

In general, we are entitled to a deduction for interest paid or accrued on indebtedness properly allocable to our trade or business during our taxable year. However, under the Tax Cuts and Jobs Act, for taxable years beginning after December 31, 2017, our deduction for “business interest” is limited to the sum of our business interest income and 30% of our “adjusted taxable income.” For the purposes of this limitation, our adjusted taxable income is computed without regard to any business interest expense or business interest income, and in the case of taxable years beginning before January 1, 2022, any deduction allowable for depreciation, amortization, or depletion to the extent such depreciation, amortization, or depletion is not capitalized into cost of goods sold with respect to inventory.

Tax-exempt entities face unique tax issues from owning our common units that may result in adverse tax consequences to them.

Investment in our common units by tax-exempt entities, such as employee benefit plans and individual retirement accounts (known as IRAs), raises issues unique to them. For example, virtually all of our income allocated to organizations that are exempt from U.S. federal income tax, including IRAs and other retirement plans, will be unrelated business taxable income and will be taxable to them. Further, with respect to taxable years beginning after December 31, 2017, subject to the proposed aggregation rules for certain similarly situated businesses or activities issued by the Treasury Department, a tax-exempt entity with more than one unrelated trade or business (including by attribution from investment in a partnership such as ours that is engaged in one or more unrelated trade or business) is required to compute the unrelated business taxable income of such tax-exempt entity separately with respect to each such trade or business (including for purposes of determining any net operating loss deduction). As a result, for years beginning after December 31, 2017, it may not be possible for tax-exempt entities to utilize losses from an investment in our partnership to offset unrelated business taxable income from another unrelated trade or business and vice versa. If you are a tax-exempt entity, you should consult your tax advisor before investing in our common units.

Non-U.S. common unitholders will be subject to U.S. taxes and withholding with respect to their income and gain from owning our common units.

Non-U.S. common unitholders are generally taxed and subject to income tax filing requirements by the United States on income effectively connected with a U.S. trade or business (“effectively connected income”). Income allocated to you and any gain from the sale of your common units will generally be considered to be “effectively connected” with a U.S. trade or business. As a result, distributions to a ~~Non~~non-U.S. common unitholder will be subject to withholding at the highest applicable effective tax rate and a ~~Non~~non-U.S. common unitholder who sells or otherwise disposes of a common unit will also be subject to U.S. federal income tax on the gain realized from the sale or disposition of that common unit.

~~The~~Moreover, ~~Tax~~the ~~Cuts~~transferee ~~and~~of ~~Jobs~~an ~~Act~~interest ~~imposes~~in a ~~withholding~~partnership ~~obligation~~that ofis engaged in a U.S. trade or business is generally required to withhold 10% of the amount realized ~~upon~~by the transferor unless the transferor certifies that it is not a ~~Non-U.S.~~foreign ~~Unitholder’s~~person, ~~sale~~and orwe are required ~~exchange~~to ofdeduct anand ~~interest~~withhold infrom athe ~~partnership~~transferee amounts that isshould ~~engaged~~have inbeen awithheld ~~U.S.~~by ~~trade~~the ortransferees ~~business~~but were not withheld. ~~However,~~Because the ~~due~~“amount torealized” ~~challenges~~includes a partner’s share of ~~administering~~the partnership’s liabilities, 10% of the amount realized acould ~~withholding~~exceed ~~obligation~~the ~~applicable~~total tocash ~~open~~purchase ~~market~~price ~~trading~~for ~~and~~the ~~other~~common ~~complications~~units. However, pending the ~~IRS~~issuance ~~has~~of ~~temporarily~~final regulations, the IRS has suspended the application of this withholding rule to ~~open market~~ transfers of ~~interest~~publicly traded interests in publicly traded partnerships. If ~~pending~~recently ~~promulgation~~promulgated ofregulations are finalized as proposed, such regulations would provide, with respect to transfers of publicly ortraded ~~other~~interests ~~guidance~~in ~~that~~publicly ~~resolves~~traded partnerships effected through a broker, that the ~~challenges.~~obligation Itto withhold is ~~not~~imposed ~~clear~~on ifthe transferor’s orbroker ~~when~~and ~~such~~that ~~regulations~~a orpartner’s ~~other~~“amount ~~guidance~~realized” ~~will~~does benot ~~issued. If~~include ~~you~~a ~~are~~partner’s share of a ~~non-U~~publicly traded partnership’s liabilities for purposes of determining the amount subject to withholding.S. ~~person~~However, ~~you~~it ~~should~~is not ~~consult~~clear ~~your~~when ~~tax~~such ~~advisor~~regulations ~~before~~will ~~investing~~be finalized and if they will be finalized in ~~our~~their ~~common~~current ~~units~~form.

We treat each purchaser of our common units as having the same tax benefits without regard to the common units actually purchased. The IRS may challenge this treatment, which could adversely affect the value of the common units.

Because we cannot match transferors and transferees of common units, we have adopted certain methods of allocating depreciation and amortization deductions that may not conform to all aspects of the Treasury Regulations. A successful IRS challenge to the use of these methods could adversely affect the amount of tax benefits available to you. It also could affect the timing of these tax benefits or the amount of gain from your sale of common units and could have a negative impact on the value of our common units or result in audit adjustments to your tax returns.

50We generally prorate our items of income, gain, loss and deduction between transferors and transferees of our common units each month based upon the ownership of our common units on the first day of each month, instead of on the basis of the date a particular common unit is transferred. The IRS may challenge this treatment, which could change the allocation of items of income, gain, loss and deduction among our common unitholders.

We generally prorate our items of income, gain, loss and deduction between transferors and transferees of our units each month based upon the ownership of our common units on the first day of each month, instead of on the basis of the date a particular common unit is transferred. The IRS may challenge this treatment, which could change the allocation of items of income, gain, loss and deduction among our common unitholders.

We generally prorate our items of income, gain, loss and deduction between transferors and transferees of our common units each month based upon the ownership of our common units on the first day of each month (the “Allocation Date”), instead of on the basis of the date a particular common unit is transferred. Similarly, we generally allocate gain or loss realized on the sale or other disposition of our assets or, in the discretion of the general partner, any other extraordinary item of income, gain, loss or deduction on the Allocation Date. Nonetheless, we allocate certain deductions for depreciation of capital additions based upon the date the underlying property is placed in service. Treasury Regulations allow a similar monthly simplifying convention, but such regulations do not specifically authorize all aspects of our proration method. If the IRS were to challenge our proration method, we could be required to change our allocation of items of income, gain, loss and deduction among our common unitholders.

A common unitholder whose common units are the subject of a securities loan (e.g., a loan to a “short seller” to cover a short sale of common units) may be considered to have disposed of those common units. If so, the common unitholder would no longer be treated for tax purposes as a partner with respect to those common units during the period of the loan and could recognize gain or loss from the disposition.

Because there are no specific rules governing the federal income tax consequences of loaning a partnership interest, a common unitholder whose common units are the subject of a securities loan may be considered to have disposed of the loaned common units. In that case, the common unitholder may no longer be treated for tax purposes as a partner in us with respect to those common units during the period of the loan to the short seller and the common unitholder may recognize gain or loss from such disposition. Moreover, during the period of the loan, any of our income, gain, loss or deduction with respect to those common units may not be reportable by the common unitholder and any cash distributions received by the common unitholder as to those common units could be fully taxable as ordinary income. Common unitholders desiring to assure their status as partners and avoid the risk of gain recognition from a securities loan should consult a tax advisor to discuss whether it is advisable to modify any applicable brokerage account agreements to prohibit their brokers from borrowing their common units.

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

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

A successful IRS challenge to these methods or allocations could adversely affect the timing or amount of taxable income or loss being allocated to our common unitholders. It also could affect the amount of gain from our common unitholders’ sale of common units and could have a negative impact on the value of the common units or result in audit adjustments to our common unitholders’ tax returns without the benefit of additional deductions.

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

In addition to U.S. federal income taxes, common unitholders will likely be subject to other taxes, including state and local taxes, unincorporated business taxes and estate, inheritance or intangible taxes that are imposed by the various jurisdictions in which we conduct business or own property now or in the future, even if they do not live in any of those jurisdictions. Our common unitholders will likely be required to file state and local income tax returns and pay state and local income taxes in some or all of these various jurisdictions. Further, common unitholders may be subject to penalties for failure to comply with those requirements.

We currently own assets and conduct business in a number of states, most of which also impose an income tax on corporations and other entities. In addition, many of these states also impose a personal income tax on individuals, corporations or other entities. As we make acquisitions or expand our business, we may own assets or conduct business in additional states that impose a personal income tax. It is your responsibility to file all U.S. federal, foreign, state and local tax returns and pay any taxes due in these jurisdictions. You should consult with your own tax advisor regarding the filing of such tax returns, the payment of such taxes, and the deductibility of any taxes paid. .

Item 1B. Unresolved Staff Comments

None.

Item 2. Properties.

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

Coal Reserves and Non-Reserve Coal Deposits

Reserves are defined by the SEC Industry Guide 7 as that part of a mineral deposit which could be economically and legally extracted or produced at the time of the reserve determination. Reserves are further classified as proven or probable according to the degree of certainty of existence. The terms and criteria utilized to estimate reserves for this study are based on United States Geological Survey Circular 891 and in general accordance with SEC Industry Guide 7, and are summarized as follows:

●

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

●

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

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

Periodically, we retain outside experts to independently verify our coal reserve and our non-reserve coal deposit estimates. The most recent audit by an independent engineering firm of our coal reserve and non-reserve coal deposit estimates was completed by Marshall Miller & Associates, Inc. as of December 31, 2018, and covered a majority of the coal reserves and non-reserve coal deposits that we controlled as of such date. We intend to continue to periodically retain outside experts to assist management with the verification of our estimates of our coal reserves and non-reserve coal deposits going forward.

Periodically, we retain outside experts to independently verify our coal reserve and our non-reserve coal deposit estimates. The outside expert performs an independent pro forma economic analysis using industry-accepted guidelines and this is used, in part, to classify tonnage as either reserve or resource, based on current market conditions. The outside expert reviews updated coal market sales price data provided by another third party, along with mine operating cost information supplied by us. Economic feasibility is considered to classify a coal deposit as either a reserve or a resource by evaluating coal thickness, overburden thickness, coal quality, costs of mining, processing, transportation, and expected selling price, among other factors. For the surface mining resource areas, the mining costs are estimated using the surface mining overburden ratios provided in the reserve evaluation. Direct mining costs are estimated for labor, blasting, fuel and lubrication supplies, repairs and maintenance, operating supplies, and other costs. The pro forma mining cost estimates for underground mining areas begin with the computation of representative total seam thickness for each area evaluated. The clean-tons-per-foot of mining advance is calculated to support mine production and productivity calculations. All underground and highwall miner coal resources is expected to require washing to remove coal partings and out-of-seam contamination. Preparation plant yield is calculated by multiplying the in-seam recovery, out-of-seam contamination, and plant efficiency factors. In-seam recovery factors is obtained from summaries of the available laboratory analyses and coal quality data. Direct mining costs are estimated for labor, supplies, maintenance and repairs, mine power and other direct mining costs. Sales, general and administration and environmental cost allocations are based on values typically observed by the third party expert. Sales variable costs for royalty payments, black lung excise tax and reclamation fees are calculated, along with cost components for other indirect mining costs and depreciation, depletion and amortization. Coal reserves are considered ~~Reserves~~to be economically recoverable at a price in excess of the cash costs to mine the coal.

The ~~following~~most ~~table~~recent ~~provides~~audit ~~information~~by an independent engineering firm of our coal reserve and non-reserve coal deposit estimates was completed by Marshall Miller & Associates, Inc. as of December 31, ~~2018~~2019, onand covered a majority of the ~~type,~~coal ~~amount~~reserves and ~~ownership~~non-reserve coal deposits that we controlled as of such date. We intend to continue to periodically retain outside experts to assist management with the verification of our estimates of our coal reserves: and non-reserve coal deposits going forward.

	Proven and Probable Coal Reserves (1)
Region	Total (3)		Proven			Probable			Assigned			Unassigned			Owned			Leased			Steam (2)			Metallurgical (2)
	(in million tons)
Central Appalachia
Tug River Complex (KY, WV)		23.0		19.8			3.2			18.8			4.3			9.2			13.8			13.0			10.0
Rob Fork Complex (KY)		14.0		12.9			1.1			14.0			-			6.4			7.6			11.6			2.4
Rhino Eastern Field (WV) (3)		33.9		19.4			14.4			29.1			4.7			-			33.9			-			33.9
Rich Mountain Field (WV)		8.2		2.7			5.5			-			8.2			8.2			-			-			8.2
Total Central Appalachia (5)		79.1		54.8			24.2			61.9			17.2			23.8			55.3			24.6			54.5
Northern Appalachia
Hopedale Complex (OH)		18.6		15.2			3.5			18.6			-			4.0			14.6			18.6			-
Leesville Field (OH)		-		-			-			-			-			-			-			-			-
Springdale Field (PA)		13.7		8.8			4.9			-			13.7			13.7			-			13.7			-
Total Northern Appalachia (5)		32.3		24.0			8.4			18.6			13.7			17.7			14.6			32.3			-
Illinois Basin
Taylorville Field (IL)		111.1		38.9			72.3			-			111.1			-			111.1			111.1			-
Pennyrile Complex (KY)		24.9		14.1			10.7			24.9			-			0.2			24.7			24.9			-
Total Illinois Basin (5)		136.0		53.0			83.0			24.9			111.1			0.2			135.8			136.0			-
Western Bituminous
Castle Valley Complex (UT)		14.9		11.3			3.6			14.9			-			-			14.9			14.9			-
McClane Canyon Mine (CO) (4)		6.2		4.1			2.1			6.2			-			0.1			6.1			6.2			-
Total Western Bituminous (5)		21.1		15.4			5.7			21.1			-			0.1			21.0			21.1			-
Total (5)		268.5		147.2			121.3			126.5			142.0			41.8			226.7			214.0			54.5
Percentage of total (5)				54.8	%		45.2	%		47.1	%		52.9	%		15.6	%		84.4	%		79.7	%		20.3	%

	(1)	Represents recoverable tons. The recoverable tonnage estimates take into account mining losses and coal wash plant losses of material from both mining dilution and any non-coal material found within the coal seams. Except for coal expected to be processed and sold on a direct-shipped basis, a specific wash plant recovery factor has been estimated from representative exploration data for each coal seam and applied on a mine-by-mine basis to the estimates. Actual wash plant recoveries vary depending on customer coal quality specifications.
	(2)	For purposes of this table, we have defined metallurgical coal reserves as reserves located in those seams that historically have been of sufficient quality and characteristics to be able to be used in the steel making process. All other coal reserves are defined as steam coal. However, some of the reserves in the metallurgical category can also be used as steam coal.
	(3)	The Rhino Eastern joint venture was dissolved in January 2015. As part of this dissolution, we received approximately 34 million tons of premium metallurgical coal reserves, which we have included in the proven and probable reserves listed above as of December 31, 2018.
	(4)	The McClane Canyon mine was permanently idled as of December 31, 2013.
	(5)	Percentages of totals are calculated based on actual amounts and not the rounded amounts presented in this table.

Substantially all of our reserves in the Central Appalachia and Western Bituminous regions are marketable as compliance coal under Phase II of the Federal Clean Air Act, while our reserves in the Northern Appalachian and Illinois Basin are not marketable as compliance coal. Compliance coal is defined by Phase II of the Federal Clean Air Act as coal having sulfur dioxide content of 1.2 pounds or less per million Btu. Electricity generators are able to use coal that exceeds these specifications by using emissions reduction technology, using emission allowance credits or blending higher sulfur coal with lower sulfur coal.

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

~~The~~Coal ~~following table provides information on particular characteristics of our coal reserves as of December 31, 2018:~~Reserves

	As Received Basis (1)										Proven and Probable Coal Reserves (2)
													Sulfur Content
Region	% Ash			% Sulfur			Btu/lb.		S02/mm Btu		Total		<1%			1-1.5%			>1.5%			Unknown
											(in million tons)
Central Appalachia
Tug River Complex (KY, WV)		9.42	%		1.19	%		13,145		1.80		23.0		9.9			9.7			2.5			0.9
Rob Fork Complex (KY)		5.41	%		1.26	%		13,527		1.87		14.0		6.5			4.3			1.6			1.6
Rhino Eastern Field (WV) (3)		4.17	%		0.67	%		14,035		0.96		33.9		28.8			4.9			-			0.2
Rich Mountain Field (WV)		7.28	%		0.60	%		13,235		0.91		8.2		8.2			-			-			-
Total Central Appalachia		6.24	%		0.91	%		13,611		1.34		79.1		53.4			18.9			4.1			2.7
Northern Appalachia
Hopedale Complex (OH)		6.66	%		2.26	%		13,738		3.30		18.6		-			-			18.6			-
Springdale Field (PA)		7.08	%		1.91	%		13,337		2.87		13.7		-			-			13.7			-
Total Northern Appalachia		6.84	%		2.11	%		13,568		3.11		32.3		-			-			32.3			-
Illinois Basin
Taylorville Field (IL)		7.75	%		3.53	%		11,057		6.38		111.1		-			-			111.1			-
Pennyrile Complex (KY)		7.79	%		2.53	%		11,475		4.42		24.9		-			-			24.9			-
Total Illinois Basin		7.76	%		3.35	%		11,133		6.01		136.0		-			-			136.0			-
Western Bituminous
Castle Valley Complex (UT)		10.58	%		0.90	%		12,055		1.49		14.9		5.3			9.6			-			-
McClane Canyon Mine (CO) (4)		11.19	%		0.57	%		11,241		1.01		6.2		6.2			-			-			-
Total Western Bituminous		10.76	%		0.80	%		11,814		1.36		21.1		11.5			9.6			-			-
Total (5)		7.45	%		2.29	%		12,194		3.76		268.5		64.9			28.5			172.4			2.7
Percentage of total (5)														24.2	%		10.6	%		64.2	%		1.0	%

The following table provides information as of December 31, 2019 on the type, amount and ownership of the coal reserves:

	(1)	As received basis represents average quality on a moist basis.
		Proven and Probable Coal Reserves (1)
	(2)	Represents recoverable tons.
Region		Total		Proven			Probable			Assigned			Unassigned			Owned			Leased			Steam (2)			Metallurgical (2)
	(3)	The Rhino Eastern joint venture was dissolved in January 2015. As part of this dissolution, we received approximately 34 million tons of premium metallurgical coal reserves, which we have included in the proven and probable reserves listed above as of December 31, 2018.
		(in million tons)
	(4)	The McClane Canyon mine was permanently idled as of December 31, 2013.
Central Appalachia
	(5)	Totals and percentages of totals are calculated based on actual amounts and not the rounded amounts presented in this table.
Tug River Complex (KY, WV)			21.2		18.0			3.2			16.9			4.3			8.8			12.4			11.8			9.4
Rob Fork Complex (KY)			12.8		11.8			1.0			12.8			-			6.1			6.7			10.4			2.4
Rhino Eastern Field (WV) (3)			33.9		19.4			14.5			29.1			4.8			-			33.9			-			33.9
Rich Mountain Field (WV)			8.2		2.7			5.5			-			8.2			8.2			-			-			8.2
Jewell Valley Complex (VA/WV)			52.6		39.3			13.3			6.1			46.5			-			52.6			-			52.6
Total Central Appalachia			128.7		91.2			37.5			64.9			63.8			23.1			105.6			22.2			106.5
Northern Appalachia
Hopedale Complex (OH)			17.5		14.0			3.5			17.5			-			4.0			13.5			17.5			-
Leesville Field (OH)			-		-			-			-			-			-			-			-			-
Springdale Field (PA)			-		-			-			-			-			-			-			-			-
Total Northern Appalachia			17.5		14.0			3.5			17.5			-			4.0			13.5			17.5			-
Illinois Basin
Taylorville Field (IL)			111.1		38.9			72.2			-			111.1			-			111.1			111.1			-
Pennyrile Complex (KY) (5)			-		-			-			-			-			-			-			-			-
Total Illinois Basin			111.1		38.9			72.2			-			111.1			-			111.1			111.1			-
Western Bituminous																	-
Castle Valley Complex (UT)			14.0		10.9			3.1			14.0			-			-			14.0			14.0			-
McClane Canyon Mine (CO) (4)			6.3		4.2			2.1			6.3			-			0.2			6.1			6.3			-
Total Western Bituminous			20.3		15.1			5.2			20.3			-			0.2			20.1			20.3			-
Total			277.6		159.2			118.4			102.7			174.9			27.3			250.3			171.1			106.5
Percentage of total (6)					57.3	%		42.7	%		37.0	%		63.0	%		9.8	%		90.2	%		61.6	%		38.4	%

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

	(2)	For purposes of this table, we have defined metallurgical coal reserves as reserves located in those seams that historically have been of sufficient quality and characteristics to be able to be used in the steel making process. All other coal reserves are defined as steam coal. However, some of the reserves in the metallurgical category can also be used as steam coal.

	(3)	The Rhino Eastern joint venture was dissolved in January 2015. As part of this dissolution, we received approximately 34 million tons of premium metallurgical coal reserves, which we have included in the proven and probable reserves listed above as of December 31, 2019.

	(4)	The McClane Canyon mine was permanently idled as of December 31, 2013.

	(5)	The Pennyrile mining complex was sold in September 2019. The operating results for the year ended December 31, 2019 are included as discontinued operations in this Form 10-K.

	(6)	Percentages of totals are calculated based on actual amounts and not the rounded amounts presented in this table.

The following table provides information on particular characteristics of our coal reserves as of December 31, 2019:

	As Received Basis (1)										Proven and Probable Coal Reserves (2)
									S02/mm				Sulfur Content
Region	% Ash			% Sulfur			Btu/lb.		Btu		Total		<1%			1-1.5%			>1.5%			Unknown
											(in million tons)
Central Appalachia
Tug River Complex (KY, WV)		9.30	%		1.18	%		13,163		1.79		21.2		9.0			9.1			2.3			0.8
Rob Fork Complex (KY)		5.42	%		1.16	%		13,523		1.72		12.8		6.5			4.3			0.4			1.6
Jewell Valley Complex (VA/WV)		4.40	%		0.81	%		14,238		1.14		52.6		41.7			8.5			-			2.4
Rhino Eastern Field (WV) (3)		4.17	%		0.67	%		14,035		0.96		33.9		28.8			4.9			-			0.2
Rich Mountain Field (WV)		7.28	%		0.60	%		13,235		0.91		8.2		8.2			-			-			-
Total Central Appalachia		5.44	%		0.85	%		13,880		1.23		128.7		94.2			26.8			2.7			5.0
Northern Appalachia
Hopedale Complex (OH)		6.69	%		2.29	%		13,780		3.32		17.5		-			-			17.5			-
Springdale Field (PA)		-			-			-		-		-		-			-			-			-
Total Northern Appalachia		6.69	%		2.29	%		13,780		3.32		17.5		-			-			17.5			-
Illinois Basin
Taylorville Field (IL)		7.75	%		3.53	%		11,057		6.38		111.1		-			-			111.1			-
Pennyrile Complex (KY) (5)		-			-			-		-		-		-			-			-			-
Total Illinois Basin		7.75	%		3.53	%		11,057		6.38		111.1		-			-			111.1			-
Western Bituminous
Castle Valley Complex (UT)		10.58	%		0.91	%		12,051		1.52		14.0		4.5			9.5			-			-
McClane Canyon Mine (CO) (4)		11.19	%		0.57	%		11,241		1.01		6.3		6.3			-			-			-
Total Western Bituminous		10.77	%		0.81	%		11,801		1.37		20.3		10.8			9.5			-			-
Total (6)		6.86	%		2.03	%		12,564		3.23		277.6		105.0			36.3			131.3			5.0
Percentage of total (6)														37.8	%		13.1	%		47.3	%		1.8	%

	(1)	As received basis represents average quality on a moist basis.

	(2)	Represents recoverable tons.

	(3)	The Rhino Eastern joint venture was dissolved in January 2015. As part of this dissolution, we received approximately 34 million tons of premium metallurgical coal reserves, which we have included in the proven and probable reserves listed above as of December 31, 2019.

	(4)	The McClane Canyon mine was permanently idled as of December 31, 2013.

	(5)	The Pennyrile mining complex was sold in September 2019. The operating results for the year ended December 31, 2019 are included as discontinued operations in this Form 10-K.

	(6)	Totals and percentages of totals are calculated based on actual amounts and not the rounded amounts presented in this table.

The following table provides the number of coal acres leased and owned, the mineralization and power source for each of our mining complexes by region as of December 31, 2019:

Region	Coal Acres Owned		Coal Acres Leased		Total Coal Acres		Formation Age	Rock Types	Power Source

Central Appalachia
Tug River Complex (KY, WV)		3,102		4,150		7,252	Pennsylvanian	Sandstone, siltstone, shale, coal	Appalachian Power Company
Rob Fork Complex (KY)		2,022		2,800		4,822	Pennsylvanian	Sandstone, siltstone, shale, coal	Kentucky Power Company
Jewell Valley Complex (VA)		26		27,325		27,351	Pennsylvanian	Sandstone, siltstone, shale, coal	Appalachian Power Company
Rhino Eastern Field (WV)		-		13,183		13,183	Pennsylvanian	Sandstone, siltstone, shale, coal	Appalachian Power Company
Rich Mountain Field (WV)		3,161		-		3,161	Pennsylvanian	Sandstone, siltstone, shale, coal	Appalachian Power Company
Total Central Appalachia		8,311		47,458		55,769
Northern Appalachia
Hopedale Complex (OH)		1,036		3,276		4,312	Pennsylvanian	Sandstone, shale, coal	American Electric Power
Leesville Field (OH)		-		-		-	Pennsylvanian	Sandstone, shale, coal	South Central Power Company
Springdale Field (PA)		-		-		-	Pennsylvanian	Sandstone, shale, coal	PPL Electric
Total Northern Appalachia		1,036		3,276		4,312
Illinois Basin
Taylorville Field (IL)		-		15,930		15,930	Pennsylvanian	Sandstone, shale, coal	American Illinois
Total Illinois Basin		-		15,930		15,930
Western Bituminous
Castle Valley Complex (UT)		-		1,516		1,516	Upper Cretaceous	Sandstone, shale, coal	Rocky Mountain Power
McClane Canyon Mine (CO)		18		848		866	Upper Cretaceous	Sandstone, shale, coal	Grand Valley Power
Total Western Bituminous		18		2,364		2,382
Grand Total		9,365		69,028		78,393

Non-Reserve Coal Deposits

The following table provides information on our non-reserve coal deposits as of December 31, ~~2018~~2019:

	Non-Reserve Coal Deposits
			Total Tons
Region	Total Tons		Owned			Leased
	(in million tons)	~~(in million tons)~~
Central Appalachia		3853.09		1011.71			2742.38
Northern Appalachia		6074.63		5569.85			4.8
Illinois Basin		3532.9		-			3532.9
Western Bituminous		29.6		-			29.6
Total		~~164~~190.17		6680.56			97110.61
Percentage of total				4042.5227	%		5957.4873	%

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

Office Facilities

We lease office space at 424 Lewis Hargett Circle, Lexington, Kentucky for our executives and administrative support staff. We executed an amendment to this lease in 2018 to extend the lease term for five additional years to July 31, 2023. In addition, we lease a building primarily for our administrative support staff at 265 Hambley Boulevard, Pikeville, Kentucky, which lease expires March 31, 2021.

Item 3. Legal Proceedings.

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

On May 3, 2019, we together with Royal (the “Plaintiffs”) filed a complaint in the Court of Chancery in the State of Delaware against Rhino Resource Partners Holdings LLC (“Holdings”), Weston Energy LLC (“Weston”), Yorktown Partners LLC and certain Yorktown funds (collectively, the “Yorktown entities”), as well as Mr. Ronald Phillips, Mr. Bryan H. Lawrence and Mr. Bryan R. Lawrence.

The complaint alleges that Holdings violated certain representations and negative covenants under an option agreement, dated December 30, 2016 among Holdings, the Plaintiffs, and Weston (the “Option Agreement”) and, as a result of Holdings’ entry into a Restructuring Support Agreement with Armstrong Energy, Inc. (“Armstrong”), its creditors and certain other parties, which agreement was entered into in advance of Armstrong’s filing for bankruptcy relief under Chapter 11 of the United States Code in November 2017. The complaint further alleges that (i) Mr. Phillips violated fiduciary and contractual duties owed to the Plaintiffs and solicited, accepted and agreed to accept certain benefits from Holdings, Weston, the Yorktown entities and Messrs. Lawrence and Lawrence without the Plaintiff’s knowledge or consent and during a period in which Mr. Phillips was the President of Royal and a director on our board and (ii) Holdings, Weston, the Yorktown entities and Messrs. Lawrence and Lawrence aided and abetted Mr. Phillips’ breaches of his fiduciary duties, tortuously interfered with the observance of Mr. Phillips’ duties under the respective organizational agreements and conferred, offered to confer and agreed to confer benefits on Mr. Phillips without the Plaintiff’s knowledge or consent.

The Plaintiffs are seeking (i) the rescission of the Option Agreement, (ii) the return of all consideration thereunder, including 5,000,000 of our common units representing limited partner interests (iii) the cancellation of the Series A Preferred Purchase Agreement, dated December 30, 2016, among the Plaintiffs and Weston (the “Series A Preferred Purchase Agreement”), (iv) the invalidation of the Series A preferred units representing limited partner interests in us issued to Weston pursuant to the Series A Preferred Purchase Agreement and (v) unspecified monetary damages arising from Mr. Phillips’ breaches of fiduciary duties and the other defendants’ aiding and abetting of such breaches.

The Yorktown entities filed an answer to the lawsuit on May 31, 2019, followed by a Motion for Judgment on the Pleadings and Motion to Dismiss. A hearing on the Motion for Judgment on the Pleadings is scheduled for April 7, 2020.

On September 23, 2019, we and Royal entered into a settlement agreement with Ronald Phillips under which Mr. Phillips was dismissed with prejudice from the lawsuit discussed above in consideration for, among other things, Mr. Phillip’s return for cancellation of up to 500,000 shares of common stock of Royal previously issued to Mr. Phillips and Mr. Phillips’ dismissal of an advancement action filed by him in reference to the lawsuit. In addition, the settlement provided for reimbursement of a portion of the legal fees claimed by Mr. Phillips and no admission of liability by any party.

Item 4. Mine Safety Disclosures.

Information concerning mine safety violations or other regulatory matters required by Section 1503(a) of the Dodd-Frank Wall Street Reform and Consumer Protection Act and Item 104 of Regulation S-K for the year ended December 31, ~~2018~~2019 is included as Exhibit 95.1 to this report.

PART II

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

Our Limited Partnership Interests

Our common units continue to trade on the OTCQB Marketplace under the ticker symbol “RHNO.”

Beginning with the quarter ended June 30, 2015 and continuing through the quarter ended December 31, ~~2018~~2019, we have suspended the cash distribution for our common units.

As of March 1520, ~~2019~~2020, we had outstanding 13,~~098~~078,~~353~~668 common units, 1,143,~~686~~171 subordinated units, 1,500,000 Series A preferred units, and a 0.4% general partner interest and incentive distribution rights (“IDRs”). As of March 1520, ~~2019~~ 2020, Royal Energy Resources, Inc. (“Royal”) owned approximately 49.45% of our outstanding common units and 93.23% of our subordinated units and our general partner. Our general partner currently owns a 0.4% general partner interest in us and all of our IDRs.

As of March 1520, ~~2019~~2020, there were 8480 holders of record of our common units. The number of record holders does not include ~~holders~~ holders of units in “street names” or persons, partnerships, associations, corporations or other entities identified in security position listings maintained by depositories.

Cash Distribution Policy

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

5558

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

	●	Our cash distribution policy is subject to restrictions on distributions under our Financing Agreement. Our Financing Agreement contains financial tests and covenants that we must satisfy. These financial tests and covenants are described in “Part II, Item 1. Business—Recent Developments-Financing Agreement.” Should we be unable to satisfy these restrictions or if we are otherwise in default under our Financing Agreement, we would be prohibited from making cash distributions notwithstanding our cash distribution policy.

	●	Our general partner will have the authority to establish cash reserves for the prudent conduct of our business and for future cash distributions to our unitholders, and the establishment of or increase in those reserves could result in a reduction in cash distributions from levels we currently anticipate pursuant to our stated cash distribution policy. Our partnership agreement does not set a limit on the amount of cash reserves that our general partner may establish.

	●	Prior to making any distribution on the common units, we will reimburse our general partner and its affiliates for all expenses they incur and payments they make on our behalf. Our partnership agreement provides that our general partner will determine in good faith the expenses that are allocable to us. The reimbursement of expenses and payment of fees, if any, to our general partner and its affiliates will reduce the amount of available cash to pay cash distributions to our unitholders.

	●	While our partnership agreement requires us to distribute all of our available cash, our partnership agreement, including provisions requiring us to make cash distributions contained therein, may be amended. Our partnership agreement generally may not be amended during the subordination period without the approval of our public common unitholders. However, our partnership agreement can be amended with the consent of our general partner and the approval of a majority of the outstanding common units after the subordination period has ended.

	●	Even if our cash distribution policy is not modified or revoked, the amount of distributions we pay under our cash distribution policy and the decision to make any distribution is determined by our general partner, taking into consideration the terms of our partnership agreement.

	●	Under Section 17-607 of the Delaware Act, we may not make a distribution if the distribution would cause our liabilities to exceed the fair value of our assets.

	●	We may lack sufficient cash to pay distributions to our unitholders due to cash flow shortfalls attributable to a number of operational, commercial or other factors as well as increases in our operating or selling, general and administrative expenses, principal and interest payments on our outstanding debt, tax expenses, working capital requirements and anticipated cash needs.

	●	If we make distributions out of capital surplus, as opposed to operating surplus, such distributions will result in a reduction in the minimum quarterly distribution and the target distribution levels. However, we do not anticipate that we will make any distributions from capital surplus.

	●	Our ability to make distributions to our unitholders depends on the performance of our subsidiaries and their ability to distribute cash to us. The ability of our subsidiaries to make distributions to us may be restricted by, among other things, the provisions of existing and future indebtedness, applicable state partnership and limited liability company laws and other laws and regulations.

5659

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

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

	●	second, 99.6% to the holders of subordinated units and 0.4% to our general partner, until each subordinated unit has received the minimum quarterly distribution of $4.45; and

	●	third, 99.6% to all unitholders, pro rata, and 0.4% to our general partner, until each unit has received a distribution of $5.1175.

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

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

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

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

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

Beginning with the quarter ended June 30, 2015 we have suspended the cash distribution for our common units. For each of the quarters ended September 30, 2014 and December 31, 2014 and March 31, 2015, we announced cash distributions at levels lower than the minimum quarterly distribution. Pursuant to our partnership agreement, our common units accrue arrearages every quarter when the distribution level is below the minimum level of $4.45 per unit. We have accumulated arrearages at December 31, ~~2018~~2019 related to the common unit distribution of approximately $~~673~~907.12 million. In addition, we have not paid any distributions on our subordinated units for any quarter after the quarter ended March 31, 2012. Our subordinated units do not accrue arrearages for unpaid distributions.

5760

Distributions on Preferred Units

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

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

Item 6. Selected Financial Data

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

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

Unless the context clearly indicates otherwise, references in this report to “we,” “our,” “us” or similar terms refer to Rhino Resource Partners LP and its subsidiaries. References to our “general partner” refer to Rhino GP LLC, the general partner of Rhino Resource Partners LP.

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

OnIn ~~November~~September 72019, ~~2017,~~ we ~~closed~~entered into an asset purchase agreement ~~with~~and a ~~third~~coal ~~party~~supply toasset ~~transfer~~purchase ~~100%~~agreement ~~of the memberships interests and~~ related ~~assets~~to ~~and liabilities in~~ our ~~Sands~~Pennyrile mining ~~Hill~~operation ~~Mining~~(“Pennyrile”) ~~entity~~with toa ~~the~~ third party. inPlease ~~exchange~~read ~~for~~below ~~a future override royalty~~ for ~~any~~additional ~~mineral sold, excluding coal, from Sands Hill Mining after the closing date~~details. Our consolidated statements of operations ~~and comprehensive income~~ have been retrospectively adjusted to reclassify our ~~Sands~~Pennyrile ~~Hill~~operations ~~Mining operation~~ to discontinued operations for the ~~year ended~~years ended December 31, ~~2017~~2019 and 2018.

Overview

Through a series of transactions completed in the first quarter of 2016, Royal Energy Resources, Inc. (“Royal”) acquired a majority ownership and control of us and 100% ownership of our general partner.

We are a diversified coal producing limited partnership formed in Delaware that is focused on coal and energy related assets and activities. We produce, process and sell high quality coal of various steam and metallurgical grades. We market our steam coal primarily to electric utility companies as fuel for their steam powered generators. Customers for our metallurgical coal are primarily steel and coke producers who use our coal to produce coke, which is used as a raw material in the steel manufacturing process.

We have a geographically diverse asset base with coal reserves located in Central Appalachia, Northern Appalachia, the Illinois Basin and the Western Bituminous region. As of December 31, 2018, we controlled an estimated 268.5 million tons of proven and probable coal reserves, consisting of an estimated 214.0 million tons of steam coal and an estimated 54.5 million tons of metallurgical coal. Proven and probable coal reserves increased approximately 15.8 million tons from 2017 to 2018 primarily as the result of the revised economic feasibility of our non-reserve coal deposits. In addition, as of December 31, 2018, we controlled an estimated 164.1 million tons of non-reserve coal deposits, which decreased primarily due to the reclassification of non-reserve coal deposits to proven and probable reserves. Periodically, we retain outside experts to independently verify our coal reserve and our non-reserve coal deposit estimates. The most recent audit by an independent engineering firm of our coal reserve and non-reserve coal deposit estimates was completed by Marshall Miller & Associates, Inc. as of December 31, 2018, and covered a majority of the coal reserves and non-reserve coal deposits that we controlled as of such date. We intend to continue to periodically retain outside experts to assist management with the verification of our estimates of our coal reserves and non-reserve coal deposits going forward.61

58We have a geographically diverse asset base with coal reserves located in Central Appalachia, Northern Appalachia, the Illinois Basin and the Western Bituminous region. As of December 31, 2019, we controlled an estimated 277.6 million tons of proven and probable coal reserves, consisting of an estimated 171.1 million tons of steam coal and an estimated 106.5 million tons of metallurgical coal. In addition, as of December 31, 2019, we controlled an estimated 190.7 million tons of non-reserve coal deposits. Periodically, we retain outside experts to independently verify our coal reserve and our non-reserve coal deposit estimates. The most recent audit by an independent engineering firm of our coal reserve and non-reserve coal deposit estimates was completed by Marshall Miller & Associates, Inc. as of December 31, 2019, and covered a majority of the coal reserves and non-reserve coal deposits that we controlled as of such date. We intend to continue to periodically retain outside experts to assist management with the verification of our estimates of our coal reserves and non-reserve coal deposits going forward.

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

For the year ended December 31, ~~2018~~2019, we generated revenues from continuing operations of approximately $~~247~~181.0 million and a net loss from continuing operations of approximately $1647.06 million. For the year ended December 31, ~~2018~~2019, we produced approximately 43.42 million tons of coal from continuing operations and sold approximately 43.60 million tons of coal from continuing operations, approximately 6482.0% of which were pursuant to long-term supply contracts.

Current Liquidity and Outlook

As of December 31, ~~2018~~2019, our available liquidity was $60.21 million. We also have a delayed draw term loan commitment in the amount of $3525 million contingent upon the satisfaction of certain conditions precedent specified in the financing agreement discussed below.

On December 27, 2017, we entered into a ~~Financing~~financing ~~Agreement~~agreement (“Financing Agreement”), which provides us with a multi-draw loan in the original aggregate principal amount of $80 million. The total principal amount is divided into a $40 million commitment, ~~the~~ the conditions for which were satisfied at the execution of the Financing Agreement and ana ~~additional~~ $3540 million additional commitment that iswas contingent upon the satisfaction of certain conditions precedent specified in the Financing Agreement. As of December 31, 2019, we had utilized $15 million of the $40 million additional commitment, which results in $25 million of the additional commitment remaining. We used approximately $17.3 million of the initial Financing Agreement net proceeds ~~thereof~~ to repay all amounts outstanding and terminate the ~~Amended~~amended and ~~Restated~~restated ~~Credit~~credit ~~Agreement~~ agreement with PNC Bank, National Association, as Administrative Agent. The Financing Agreement ~~terminates~~initially onhad a termination date of December 27, 2020, which was amended to December 27, 2022 per the fifth amendment to the Financing Agreement discussed further below. For more information about our Financing Agreement, please read “— Liquidity ~~Recent~~and ~~Developments~~Capital Resources—Financing Agreement.”

WeBeginning ~~continue~~in tothe ~~take~~later ~~measures,~~part ~~including~~of the ~~suspension~~third quarter of ~~cash~~2019, ~~distributions~~we onhave ~~our~~experienced ~~common~~significantly ~~and~~weaker ~~subordinated~~market ~~units~~demand and ~~cost~~have seen prices move lower for the qualities of met and ~~productivity~~steam coal we produce. This downward price trend has been exacerbated by the recent coronavirus ~~improvements,~~pandemic. In response to ~~enhance~~this reduced demand and ~~preserve~~to the significant health threats to our ~~liquidity~~employees, soon ~~that~~March 20, 2020, we ~~can~~temporarily idled ~~fund~~production at several of our ~~ongoing~~mines. ~~operations~~We will continue to monitor conditions to ensure the health and ~~necessary~~welfare ~~capital~~of ~~expenditures~~our employees. ~~and~~We ~~meet~~do not expect the idling of the coal production activities will affect our ~~financial~~ability to fulfill current customer commitments, as loading and ~~debt~~shipping ~~service~~crews ~~obligations~~will remain in place to ship coal from existing inventories.

If we continue to experience weak demand and prices continue to lower for our met and steam coal, we may not be able to continue to give the required representations or meet all of the covenants and restrictions included in our Financing Agreement. If we violate any of the covenants or restrictions in our Financing Agreement, including the fixed-charge coverage ratio, some or all of our indebtedness may become immediately due and payable, and our Lenders may not be willing to make any loans under the additional commitment available under our Financing Agreement. If we are unable to give a required representation or we violate a covenant or restriction, then we will need a waiver from our Lenders under our Financing Agreement, or they may declare an event of default and, after applicable specified cure periods, all amounts outstanding under the Financing Agreement would become immediately due and payable. Although we believe our Lenders are well secured under the terms of our Financing Agreement, there is no assurance that the Lenders would agree to any such waiver. Failure to obtain financing or to generate sufficient cash flow from operations could cause us to further curtail our operations and reduce spending and alter our business plan. We are currently considering alternatives to address our liquidity and balance sheet issues, such as selling additional assets or seeking merger opportunities, and depending on the urgency of our liquidity constraints, we may be required to pursue such an option at an inopportune time.

As of December 31, 2019, we are unable to demonstrate that we have sufficient liquidity to operate our business over the next twelve months from the date of filing our Annual Report on Form 10-K and thus substantial doubt is raised about our ability to continue as a going concern. Accordingly, our independent registered public accounting firm has included an emphasis paragraph with respect to our ability to continue as a going concern in its report on our consolidated financial statements for the year ended December 31, 2019. The presence of the going concern emphasis paragraph in our auditors’ report may have an adverse impact on our relationship with third parties with whom we do business, including our customers, vendors, lenders and employees, making it difficult to raise additional financing to the extent needed to conduct normal operations. As a result, our business, results of operations, financial condition and prospects could be materially adversely affected.

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

Recent Developments

Pennyrile Mine Complex (“Pennyrile”) Asset Purchase Agreement

Coal Supply Asset Purchase Agreement

On September 6, 2019, we entered into an Asset Purchase Agreement with the Buyer and Buyer Parent for the sale and assignment of certain coal supply agreements associated with Pennyrile (the “Coal Supply APA”) in exchange for approximately $7.3 million. The Coal Supply APA includes customary representations of the parties thereto and indemnification for losses arising from the breaches of such representations and for liabilities arising during the period in which the relevant parties were not party to the coal supply agreements. The transactions contemplated by the Coal Supply APA closed upon the execution thereof.

Discontinued Operations

The Pennyrile operating results for the year ended December 31, 2019 and 2018 are recorded as discontinued operations, including a $38.7 million impairment loss associated with the sale.

Blackjewel Assignment Agreement

Settlement Agreement

On June 28, 2019, we entered into a settlement agreement with a third party which allows the third party to maintain certain pipelines pursuant to designated permits at our Central Appalachia operations. The agreement required the third party to pay us $7.0 million in consideration. We received $4.2 million on July 3, 2019 and the balance of $2.8 million was received on January 2, 2020. We recorded a gain of $6.9 million during the second quarter of 2019 related to this settlement agreement.

Financing Agreement

On ~~December~~February 2713, ~~2017~~2019, we entered into a second amendment (“Amendment”) to the Financing Agreement. ~~with~~The ~~Cortland~~Amendment ~~Capital~~provided the ~~Market~~Lender’s ~~Services~~consent ~~LLC,~~for asus ~~Collateral~~to ~~Agent~~pay ~~and~~a ~~Administrative agent,~~one-time CBcash ~~Agent~~distribution ~~Services~~on ~~LLC~~February 14, as2019 ~~Origination~~to ~~Agent~~the ~~and~~Series ~~the~~A ~~parties~~Preferred ~~identified~~Unitholders not asto ~~Lenders~~exceed ~~(the~~approximately ~~“Lenders”)~~$3.2 ~~therein, pursuant~~million. toThe ~~which~~Amendment ~~Lenders~~allowed ~~agreed~~us to ~~provide~~sell usour ~~with~~remaining ashares ~~multi-draw~~of ~~term~~Mammoth ~~loan~~Energy inServices, Inc. (NASDAQ: TUSK)(“Mammoth Inc.”) and utilize the ~~aggregate~~proceeds ~~principal~~for ~~amount~~payment of ~~$80~~the ~~million,~~one-time ~~subject~~ cash distribution to the ~~terms~~Series A Preferred Unitholders and ~~conditions~~waived ~~set~~the ~~forth~~requirement into use such proceeds to prepay the outstanding principal amount outstanding under the Financing Agreement. The ~~total~~Amendment ~~principal~~also ~~amount~~waived isany ~~divided~~Event ~~into~~of aDefault ~~$40~~that ~~million~~has ~~commitment,~~or would otherwise arise under Section 9.01(c) of the ~~conditions~~Financing ~~for~~Agreement ~~which~~solely ~~were~~by ~~satisfied~~reason atof us failing to comply with the ~~execution~~Fixed Charge Coverage Ratio covenant in Section 7.03(b) of the Financing Agreement ~~(“Effective~~for ~~Date~~the ~~Term~~fiscal ~~Loan~~quarter ~~Commitment”) and~~ending December 31, 2018. The Amendment includes an ~~additional~~amendment fee of approximately $350.6 million ~~commitment~~payable ~~that~~by isus ~~contingent~~on ~~upon~~May ~~the~~13, ~~satisfaction~~2019 and an exit fee equal to 1% of ~~certain~~the ~~conditions~~principal ~~precedent~~amount ~~specified~~of inthe term loans made under the Financing Agreement ~~(“Delayed~~that ~~Draw~~is ~~Term~~payable ~~Loan~~on ~~Commitment”~~the earliest of (w). ~~Loans~~the ~~made~~final ~~pursuant~~maturity todate of the Financing Agreement ~~are~~, ~~secured~~(x) bythe ~~substantially~~termination ~~all~~date of ~~our~~the ~~assets.~~Financing ~~The~~Agreement, (y) the acceleration of the obligations under the Financing Agreement ~~terminates~~for any onreason, ~~December~~including, 27without limitation, ~~2020.~~acceleration ~~For~~in ~~more~~accordance ~~information~~with ~~about our~~Section 9.01 of the Financing Agreement, ~~please~~including as ~~read~~a “—result ~~Liquidity~~of the commencement of an insolvency proceeding and ~~Capital~~(z) ~~Resources—~~the date of any refinancing of the term loan under the Financing Agreement. The Amendment amended the definition of the Make-Whole Amount under the Financing Agreement to extend the date of the Make-Whole Amount period to December 31, 2019.”

59On May 8, 2019, we entered into a third amendment (“Third Amendment”) to the Financing Agreement. The Third Amendment includes the Lenders’ agreement to waive any Event of Default that arose or would otherwise arise under the Financing Agreement for failing to comply with the Fixed Charge Coverage Ratio for the six months ended March 31, 2019. The Third Amendment increased the original exit fee of 3.0% to 6.0%. The original exit fee of 3% was included in the Financing Agreement at the execution date and the increase of the total exit fee to 6% was included as part of the amendment dated February 13, 2019 discussed above and this Third Amendment. The exit fee is applied to the principal amount of the loans made under the Financing Agreement that is payable on the earliest of (a) the final maturity date, (b) the termination date of the Financing agreement for any reason, (c) the acceleration of the obligations in the Financing Agreement for any reason and (d) the date of any refinancing of the term loan under the Financing Agreement.

On April 17, 2018, we amended the Financing Agreement to allow for certain activities including a sale leaseback of certain pieces of equipment, the due date for the lease consents was extended to June 30, 2018 and confirmation of the distribution to holders of the Series A preferred units of $6.0 million (accrued in our consolidated financial statements at December 31, 2017). Additionally, the amendments provide that we could sell additional shares of Mammoth Inc. stock and retain 50% of the proceeds with the other 50% used to reduce debt. We reduced the debt by $3.4 million with proceeds from the sale of Mammoth Inc. stock in the second quarter of 2018.64

On ~~July~~August 2716, ~~2018~~2019, we entered into a ~~consent~~fourth ~~with~~amendment ~~our~~(the ~~Lenders~~“Fourth ~~related~~Amendment”) to the Financing Agreement. ~~The consent included the lenders~~originally ~~agreement~~executed ~~to make a $5 million loan from the Delayed Draw Term Loan Commitment, which was repaid in full~~ on ~~October~~December 2627, ~~2018~~2017 ~~pursuant to~~with the ~~terms of the consent~~Lenders. The ~~consent~~Fourth ~~also~~Amendment ~~included~~provided a ~~waiver~~$5.0 ofmillion ~~the~~term ~~requirements~~loan ~~relating~~provided toby the ~~use~~Lenders to ofus ~~proceeds~~under ofthe ~~any~~delayed ~~sale of~~draw ~~the~~feature ~~shares~~ of ~~Mammoth Inc. set forth in~~ the ~~consent to the~~ Financing Agreement, ~~dated as of April 17, 2018~~ and ~~also~~extended ~~waived any~~the ~~Event~~period ofby ~~Default~~which ~~that~~an ~~arose~~applicable orpremium ~~would~~payable to ~~otherwise arise under~~ the ~~Financing~~Lenders ~~Agreement~~will ~~for~~be ~~failing~~calculated to ~~comply with~~ the ~~Fixed~~final ~~Charge Coverage~~maturity ~~Ratio for the six months ended June 30, 2018~~date.

On ~~November~~September 86, ~~2018~~2019, we entered into a ~~consent~~fifth ~~with~~amendment ~~our~~(the ~~Lenders~~“Fifth ~~related~~Amendment”). toThe Fifth Amendment (i) extended the maturity of the Financing Agreement to December 27, 2022, (ii) provided a $5.0 ~~The~~million ~~consent~~term ~~includes~~loan provided by the ~~lenders agreement~~Lenders to ~~waive~~us under ~~any~~the ~~Event~~delayed draw feature of ~~Default~~the ~~that~~Financing ~~arose~~Agreement, or(iii) ~~would~~extended ~~otherwise~~the ~~arise~~period ~~under~~by which an applicable premium payable to the ~~Financing~~Lenders ~~Agreement~~will ~~for~~be ~~failing~~calculated to ~~comply~~December 31, 2021, (iv) modified certain definitions and concepts to account for our recent ~~with~~acquisition of properties from Blackjewel, (v) permitted the ~~Fixed~~disposition ~~Charge~~of ~~Coverage~~the ~~Ratio~~Pennyrile mining complex and (vi) provided for the payment of additional fees to the ~~six~~Lenders, ~~months~~including ~~ended~~a ~~September~~consent 30fee of $1.0 million, ~~2018~~an amendment fee of $825,000 and an increase in the lender exit fee of 1.00% to a total exit fee of 7.0% of the amount of term loans made under the Financing Agreement that is payable at the maturity of the Financing Agreement.

On ~~December~~March 202, ~~2018~~2020, we entered into a ~~limited~~sixth ~~waiver~~amendment ~~and consent~~ (the “~~Waiver~~Sixth Amendment”) to the Financing Agreement. The ~~Waiver relates~~Sixth ~~to the sales of certain real property in Western Colorado~~Amendment, ~~the net proceeds of which are required to be used to reduce~~ ~~our~~among ~~debt~~other ~~under~~things, ~~the~~provides ~~Financing~~a ~~Agreement.~~consent Asby of the ~~date~~Origination ofAgent ~~the~~to ~~Waiver,~~a ~~we had sold 9 individual lots in smaller transactions~~$3.0 ~~Rather than~~million ~~transmitting~~delayed ~~net~~draw ~~proceeds~~term ~~with~~loan ~~respect~~and toincreases ~~each individual transaction, we agreed with~~ the ~~Lenders in principle to delay repayment~~lender ~~until~~exit anfee ~~aggregate~~payable ~~payment~~by ~~could be made at~~ the ~~end~~Partnership ~~of 2018. On December 18, 2018, we used the sale proceeds of approximately $379,000~~ to ~~reduce~~ the ~~debt. The Waiver (i) contains a ratification by the~~ Lenders ofupon the ~~sale~~maturity ~~of the individual lots to~~ date ~~and~~ ~~waives the associated technical defaults under the Financing Agreement for not making immediate payments of net proceeds therefrom,~~ (~~ii)~~or ~~permits~~earlier ~~the~~termination ~~sale~~or ofacceleration ~~certain specified additional lots and (iii~~date) ~~subject~~by ~~to Lender consent, permits the sale of other lots~~an onadditional ~~a going forward basis~~1. ~~The net proceeds of future sales will be held by us until a later date to be determined by the Lenders~~0%.

On February 13, 2019, we entered into a second amendment (“Amendment”) to the Financing Agreement. The Amendment provides the Lender’s consent for us to pay a one-time cash distribution on February 14, 2019 to the Series A Preferred Unitholders not to exceed approximately $3.2 million. The Amendment allows us to sell our remaining shares of Mammoth Energy Services, Inc. and utilize the proceeds for payment of the one-time cash distribution to the Series A Preferred Unitholders and waives the requirement to use such proceeds to prepay the outstanding principal amount outstanding under the Financing Agreement. The Amendment also waives any Event of Default that has or would otherwise arise under Section 9.01(c) of the Financing Agreement solely by reason of us failing to comply with the Fixed Charge Coverage Ratio covenant in Section 7.03(b) of the Financing Agreement for the fiscal quarter ending December 31, 2018. The Amendment includes an amendment fee of approximately $0.6 million payable by us on May 13, 2019 and an exit fee equal to 1% of the principal amount of the term loans made under the Financing Agreement that is payable on the earliest of (w) the final maturity date of the Financing Agreement, (x) the termination date of the Financing Agreement, (y) the acceleration of the obligations under the Financing Agreement for any reason, including, without limitation, acceleration in accordance with Section 9.01 of the Financing Agreement, including as a result of the commencement of an insolvency proceeding and (z) the date of any refinancing of the term loan under the Financing Agreement. The Amendment amends the definition of the Make-Whole Amount under the Financing Agreement to extend the date of the Make-Whole Amount period to December 31, 2019.

Common Unit Warrants

In December 2017, we entered into a warrant agreement with certain parties that are also parties to the Financing Agreement discussed above. The warrant agreement included the issuance of a total of 683,888 warrants of our common units (“Common Unit Warrants”) at an exercise price of $1.95 per unit, which was the closing price of our common units on the OTC market as of December 27, 2017. The Common Unit Warrants have a five year expiration date. The Common Unit Warrants and our common units after exercise are both transferable, subject to applicable US securities laws. The Common Unit Warrant exercise price is $1.95 per unit, but the price per unit will be reduced by future common unit distributions and other further adjustments in price included in the warrant agreement for transactions that are dilutive to the amount of Rhino’s common units outstanding. The warrant agreement includes a provision for a cashless exercise where the warrant holders can receive a net number of common units. Per the warrant agreement, the warrants are detached from the Financing Agreement and fully transferable.

Letter of Credit Facility – PNC Bank

On December 27, 2017, we entered into a master letter of credit facility, security agreement and reimbursement agreement (the “LoC Facility Agreement”) with PNC Bank, National Association (“PNC”), pursuant to which PNC agreed to provide us with a facility for the issuance of standby letters of credit used in the ordinary course of our business (the “LoC Facility”). The LoC Facility Agreement provided that we pay a quarterly fee at a rate equal to 5% per annum calculated based on the daily average of letters of credit outstanding under the LoC Facility, as well as administrative costs incurred by PNC and a $100,000 closing fee. The LoC Facility Agreement provided that we reimburse PNC for any drawing under a letter of credit by a specified beneficiary as soon as possible after payment was made. Our obligations under the LoC Facility Agreement were secured by a first lien security interest on a cash collateral account that was required to contain no less than 105% of the face value of the outstanding letters of credit. In the event the amount in such cash collateral account was insufficient to satisfy our reimbursement obligations, the amount outstanding would bear interest at a rate per annum equal to the Base Rate (as that term was defined in the LoC Facility Agreement) plus 2.0%. We would indemnify PNC for any losses which PNC may have incurred as a result of the issuance of a letter of credit or PNC’s failure to honor any drawing under a letter of credit, subject in each case to certain exceptions. We provided cash collateral to our counterparties during the third quarter of 2018 and as of September 30, 2018, the LoC Facility was terminated. We had no outstanding letters of credit as of December 31, 2018.

Distribution Suspension

Beginning with the quarter ended June 30, 2015 and continuing through the quarter ended December 31, 2018, we have suspended the cash distribution on our common units. For each of the quarters ended September 30, 2014, December 31, 2014 and March 31, 2015, we announced cash distributions per common unit at levels lower than the minimum quarterly distribution. We have not paid any distribution on our subordinated units for any quarter after the quarter ended March 31, 2012. The distribution suspension and prior reductions were the result of prolonged weakness in the coal markets, which has continued to adversely affect our cash flow.

Pursuant to our partnership agreement, our common units accrue arrearages every quarter when the distribution level is below the minimum level of $4.45 per unit. Since our distributions for the quarters ended September 30, 2014, December 31, 2014 and March 31, 2015 were below the minimum level and we altogether suspended the distribution beginning with the quarter ended June 30, 2015, we have accumulated arrearages at December 31, ~~2018~~2019 related to the common unit distribution of approximately $~~673~~907.12 million.

Asset Impairments-~~2018~~2019

We performed a comprehensive review of our current coal mining operations as well as potential future development projects ~~for~~to ~~the~~ascertain any ~~year~~potential ~~ended~~impairment losses during 2019. We identified two properties that were impaired based upon changes in market conditions, ~~December~~financing 31alternatives or other factors, ~~2018~~specifically toat ~~ascertain~~our Rhino Eastern and Taylorville Mining undeveloped properties where market conditions related to any ~~potential~~future ~~impairment~~development ~~losses~~deteriorated in the fourth quarter of 2019. We ~~did~~determined ~~not~~that ~~record~~the ~~any~~probability of ~~impairment~~obtaining ~~losses~~the financing required for ~~coal~~these ~~properties~~projects would be remote as of December 31, ~~mine development~~2019. ~~costs~~We orrecorded ~~coal~~approximately ~~mining~~$26.0 million ~~equipment~~of total asset impairment and related ~~facilities~~charges related to these undeveloped properties for the year ended December 31, 2019, ~~2018~~which is recorded on the Asset impairment and related charges line of the consolidated statements of operations. The $26.0 million impairment included a $17.9 million impairment related to future development of Rhino Eastern and an $8.1 million impairment related to future development of Taylorville Mining LLC.

Asset Impairments-2017

We performed a comprehensive review of our coal mining operations as well as potential future development projects for the year ended December 31, 2017 to ascertain any potential impairment losses. We engaged an independent third party to perform a fair market value appraisal on certain parcels of land that we own in Mesa County, Colorado. The parcels appraised for $6.0 million compared to the carrying value of $6.8 million. We recorded an impairment loss of $0.8 million, which is recorded on the Asset impairment and related charges line of the consolidated statements of operations and comprehensive income. No other coal properties, mine development costs or other coal mining equipment and related facilities were impaired as of December 31, 2017.

We recorded an impairment charge of $21.8 million related to the call option received from a third party to acquire substantially all of the outstanding common stock of Armstrong Energy, Inc. On October 31, 2017, Armstrong Energy filed Chapter 11 petitions in the Eastern District of Missouri’s United States Bankruptcy Court. Per the Chapter 11 petitions, Armstrong Energy filed a detailed restructuring plan as part of the Chapter 11 proceedings. On February 9, 2018, the U.S. Bankruptcy Court confirmed Armstrong Energy’s Chapter 11 reorganization plan and as such we concluded that the call option had no carrying value. An impairment charge of $21.8 million related to the call option was recorded on the Asset impairment and related charges line of the consolidated statements of operations and comprehensive income.

Factors That Impact Our Business

Our results of operations in the near term could be impacted by a number of factors, including (1) our ability to fund our ongoing operations and necessary capital expenditures, (2) the availability of transportation for coal shipments, (3) poor mining conditions resulting from geological conditions or the effects of prior mining, (4) equipment problems at mining locations, (5) adverse weather conditions and natural disasters or (6) the availability and costs of key supplies and commodities such as steel, diesel fuel and explosives.

On a long-term basis, our results of operations could be impacted by, among other factors, (1) our ability to fund our ongoing operations and necessary capital expenditures, (2) changes in governmental regulation, (3) the availability and prices of competing electricity-generation fuels, (4) the world-wide demand for steel, which utilizes metallurgical coal and can affect the demand and prices of metallurgical coal that we produce, (5) our ability to secure or acquire high-quality coal reserves and (6) our ability to find buyers for coal under favorable supply contracts.

We have historically sold a majority of our coal through supply contracts and anticipate that we will continue to do so. As of December 31, ~~2018~~2019, we had commitments under supply contracts to deliver annually scheduled base quantities of coal as follows:

Year	Tons ~~(in thousands)~~		Number of customers
2019		3,699	18
	(in thousands)
2020		1,~~979~~734	6	12
2021		~~352~~400	2	3
2022		250		3

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

Results of Operations

Segment Information

As of December 31, ~~2018~~2019, we have ~~four~~three reportable business segments: Central Appalachia, Northern Appalachia, and Rhino Western ~~and Illinois Basin~~. Additionally, we have an Other category that includes our ancillary businesses. Our Central Appalachia segment consists of ~~two~~three mining complexes: Tug River, ~~and~~ Rob Fork and Jewell Valley, which, as of December 31, ~~2018~~2019, together included ~~one~~five underground ~~mine~~mines, three ~~surface~~ surface mines and ~~three~~four preparation plants and loadout facilities in eastern Kentucky, Virginia and southern West Virginia. Our Northern Appalachia segment consists of the Hopedale mining complex and the Leesville field. The Hopedale mining complex, located in northern Ohio, ~~included~~includes one underground mine and one preparation plant and loadout facility as of December 31, ~~2018~~2019. Our Rhino Western segment includes one underground mine in the Western Bituminous region at our Castle Valley mining complex in Utah. Our Illinois Basin segment includes one underground mine, preparation plant and river loadout facility at our Pennyrile mining complex located in western Kentucky, as well as our Taylorville field reserves located in central Illinois. Our Other category is comprised of our ancillary businesses.

Evaluating Our Results of Operations

Our management uses a variety of non-GAAP financial measurements to analyze our performance, including (1) Adjusted EBITDA, (2) coal revenues per ton and (3) cost of operations per ton.

Adjusted EBITDA. The discussion of our results of operations below includes references to, and analysis of, our segments’ Adjusted EBITDA results. Adjusted EBITDA represents net income before deducting interest expense, income taxes and depreciation, depletion and amortization, while also excluding certain non-cash and/or non-recurring items. Adjusted EBITDA is used by management primarily as a measure of our segments’ operating performance. Adjusted EBITDA should not be considered an alternative to net income, income from operations, cash flows from operating activities or any other measure of financial performance or liquidity presented in accordance with GAAP. Because not all companies calculate Adjusted EBITDA identically, our calculation may not be comparable to similarly titled measures of other companies. Please read “—Reconciliation of Adjusted EBITDA” for reconciliations of Adjusted EBITDA to net income by segment for each of the periods indicated.

Coal Revenues Per Ton. Coal revenues per ton represents coal revenues divided by tons of coal sold. Coal revenues per ton is a key indicator of our effectiveness in obtaining favorable prices for our product.

Cost of Operations Per Ton. Cost of operations per ton sold represents the cost of operations (exclusive of DD&A) divided by tons of coal sold. Management uses this measurement as a key indicator of the efficiency of operations.

OnSummary. ~~November~~(Unless 7,otherwise ~~2017~~specified, wethe ~~closed~~following andiscussion ~~agreement with a third party to transfer 100%~~ of the ~~membership~~results ~~interests~~of ~~and~~operations ~~related~~for ~~assets and liabilities in Sands Hill Mining LLC to~~ the ~~third~~years ~~party~~ended inDecember ~~exchange for a future override royalty for any mineral sold~~31, ~~excluding coal,~~2019 ~~from~~and ~~Sands Hill Mining LLC after the closing date. We recognized a gain of $3.2 million from the sale of Sands Hill Mining~~2018 ~~LLC~~excludes ~~since~~operating ~~the~~results ~~third~~relating ~~party~~to ~~assumed the reclamation obligations associated with this operation~~Pennyrile. The ~~historical~~Pennyrile operating results ~~for~~are ~~Sands Hill~~recorded ~~Mining~~as ~~LLC~~discontinued ~~together~~operations in ~~with~~our ~~the~~consolidated ~~gain~~statements onof ~~sale have been presented as discontinued~~ operations.)

~~Summary. (~~The following ~~discussions~~table ofsets ~~financial~~forth certain information regarding our revenues, operating expenses, other income and ~~operational~~expenses, and operational data for ~~the~~ years ended December 31, ~~2018~~2019 and ~~2017 pertain to continuing operations unless otherwise specified.)~~2018:

The following table sets forth certain information regarding our revenues, operating expenses, other income and expenses, and operational data for years ended December 31, 2018 and 2017:

	Year Ended December 31,						Increase/(Decrease)
	2019			2018			$			% *
	(in millions, except per ton data and %)
Statement of Operations Data:

Coal revenues	$	178.9		$	193.8		$	(14.9	)		(7.7	%)
Other revenues		2.1			2.7			(0.6	)		(22.7	%)
Total revenues		181.0			196.5			(15.5	)		(7.9	%)
Costs and expenses:
Cost of operations (exclusive of DD&A shown separately below)		167.4			163.6			3.8			2.4	%
Freight and handling costs		4.7			9.1			(4.4	)		(47.7	%)
Depreciation, depletion and amortization		14.5			14.4			0.1			0.2	%
Selling, general and administrative (exclusive of DD&A shown separately above)		14.9			12.6			2.3			17.3	%
Asset impairment and related charges		26.0			-			26.0			n/a
Loss/(Gain) on sale/disposal of assets		(6.7	)		(3.3	)		(3.4	)		96.7	%
(Loss)/Income from operations		(39.8	)		0.1			(39.9	)		(50026.1	%)
Interest expense and other		(7.9	)		(8.5	)		0.6			(7.4	%)
Interest income and other		0.1			0.1			-			(86.7	%)
Total interest and other (income) expense		(7.8	)		(8.4	)		0.6			(6.8	%)
Net (loss) from continuing operations		(47.6	)		(8.3	)		(39.3	)		471.0	%
Net (loss) from discontinued operations		(51.9	)		(7.7	)		(44.2	)		574.8	%
Net (loss)	$	(99.5	)	$	(16.0	)		(83.5	)		520.8	%

Total tons sold (in thousands except %)		2,989.8			3,310.0			(320.2	)		(9.7	%)
Coal revenues per ton	$	59.84		$	58.55		$	1.29			2.2	%
Cost of operations per ton	$	56.00		$	49.41		$	6.59			13.3	%

Other Financial Data
Adjusted EBITDA from continuing operations	$	1.5		$	19.4		$	(17.9	)		(92.5	%)
Adjusted EBITDA from discontinued operations	$	(7.2	)	$	0.2		$	(7.4	)		(3398.2	%)
Adjusted EBITDA	$	(5.7	)	$	19.6		$	(25.3	)		(129.5	%)

	Year Ended December 31,						Increase/(Decrease)
	2018			2017			$			% *
	(in millions, except per ton data and %)
Statement of Operations Data:
Coal revenues	$	244.3		$	217.2		$	27.1			12.5	%
Other revenues		2.7			1.5			1.2			84.6	%
Total revenues		247.0			218.7			28.3			13.0	%
Costs and expenses:
Cost of operations (exclusive of DD&A shown separately below)		213.6			178.5			35.1			19.7	%
Freight and handling costs		9.0			1.8			7.2			394.5	%
Depreciation, depletion and amortization		22.3			21.1			1.2			5.8	%
Selling, general and administrative (exclusive of DD&A shown separately above)		12.9			11.4			1.5			13.0	%
Asset impairment and related charges		-			22.6			(22.6	)		(100.0	%)
Impact from adoption of ASU 2016-01		0.2			-			0.2			n/a
(Gain)/loss on sale/disposal of assets		(3.4	)		-			(3.4	)		n/a
(Loss) from operations		(7.6	)		(16.7	)		9.1			(54.5	%)
Interest expense and other		8.5			4.0			4.5			111.5	%
Interest income and other		(0.1	)		(0.1	)		-			(21.9	%)
Total interest and other (income) expense		8.4			3.9			4.5			116.5	%
Net (loss) from continuing operations		(16.0	)		(20.6	)		4.6			(22.3	%)
Net income from discontinued operations		-			1.8			(1.8	)		(100.0	%)
Net (loss)	$	(16.0	)	$	(18.8	)	$	2.8			(14.7	%)
Total tons sold		4,598.0			4,125.6			472.4			11.5	%
Coal revenues per ton	$	53.13		$	52.64		$	0.49			0.9	%
Cost of operations per ton	$	46.45		$	43.26		$	3.19			7.4	%
Other Financial Data
Adjusted EBITDA from continuing operations	$	19.6		$	27.1		$	(7.5	)		(27.9	%)
Adjusted EBITDA from discontinued operations		-			(0.8	)		0.8			(100.0	%)
Adjusted EBITDA	$	19.6		$	26.3		$	(6.7	)		(25.5	%)

*	Percentages and per ton amounts are calculated based on actual amounts and not the rounded amounts presented in this table.

6367

Year Ended December 31, ~~2018~~2019 Compared to Year Ended December 31, ~~2017~~2018

~~Summary~~Revenues. For the year ended December 31, ~~2018~~2019, our total revenues ~~increased~~decreased to $~~247~~181.0 million from $~~218~~196.75 million for the year ended December 31, ~~2017~~2018. We sold 4approximately 3.60 million tons of coal during the year ended December 31, ~~2018~~2019, which was ana ~~increase~~ decrease of 0.5 3 million tons, or ana 119.57% ~~increase~~decrease, from the 43.13 million tons of coal sold during the year ended December 31, ~~2017~~2018. The ~~increase~~decrease in revenue and tons sold was primarily the result of ~~increased~~decreased sales in Central Appalachia due to anlower ~~increase in~~ demand for met and steam coal produced in this region.

Cost of Operations. Total cost of operations increased by $353.18 million or 192.74% to $~~213~~167.64 million for the year ended December 31, ~~2018~~2019 as compared to $~~178~~163.56 million for the year ended December 31, ~~2017~~2018. Our cost of operations per ton was $4656.4500 for the year ended December 31, ~~2018~~2019, an increase of $36.1959, or 713.43%, from the year ended December 31, ~~2017~~2018. The increase in cost of operations per ton was primarily due to the ~~$33.5 million~~ increase in cost of operations at our ~~Central~~Northern Appalachia operations as ~~demand~~we ~~for~~encountered ~~met and~~adverse ~~steam~~geological ~~coal~~conditions ~~increased~~during ~~in this region~~2019. We also experienced an increase in the cost ~~for~~of ~~diesel~~labor ~~fuel,~~at ~~contract~~all ~~services~~of ~~and equipment maintenance in~~ our ~~Central~~segments ~~Appalachia~~and ~~segment~~an ~~which resulted~~ increase in ~~the~~equipment ~~cost~~maintenance ofat ~~operations~~our ~~per~~Central ~~ton~~Appalachia ~~increasing during 2018 compared to 2017~~operations.

Freight and Handling. Total freight and handling cost ~~increased~~decreased to $94.07 million for the year ended December 31, ~~2018~~2019 as compared to $19.81 million for the year ended December 31, ~~2017~~2018. The ~~increase~~decrease in freight and handling costs was primarily the result of ~~rail~~fewer ~~transportation costs in our Central Appalachia operations as we executed more~~ export ~~coal~~ sales ~~in the period~~ that ~~required~~require us to pay ~~for~~ railroad transportation to the port of export. We also incurred $1.11million in demurrage charges during 2018 due to rail transportation constraints that caused shipments to be delayed to the port of export.

Depreciation, Depletion and Amortization. Total DD&A expense for the year ended December 31, ~~2018~~2019 was $2214.35 million as compared to $2114.14 million for the year ended December 31, ~~2017~~2018.

64For the year ended December 31, 2019, our depreciation expense increased to $10.4 million compared to $10.3 million for the year ended December 31, 2018.

For the year ended December 31, ~~2018~~2019, our ~~depreciation~~depletion expense ~~increased~~decreased to $161.96 million compared to $161.27 million for the year ended December 31, ~~2017~~2018. This ~~increase~~decrease ~~was~~is ~~the~~primarily ~~result~~due ofto ~~adding~~the ~~new~~decrease ~~equipment~~in totons ~~meet~~produced ~~the~~in ~~increased~~2019 ~~demand~~compared ~~for~~to ~~coal~~2018.

For the year ended December 31, ~~2018~~2019, our ~~depletion~~amortization expense ~~increased~~was toapproximately $12.95 million compared to $12.74 million for the year ~~ended~~ ended December 31, ~~2017. This increase is primarily due to the increase in tons produced in~~ 2018 ~~compared to 2017~~.

~~For~~Selling, General and Administrative. SG&A expense for the year ended December 31, ~~2018,~~2019 ~~our amortization expense~~ increased to $314.69 million as compared to $312.26 million for the year ended December 31, ~~2017~~2018 primarily due to a $2.0 ~~The~~million ~~increase~~expense isrecorded as the result of ~~increased~~an ~~production~~agreement reached atwith a third party to assume the surety bonds associated with Sands Hill Mining LLC that had not been transferred from our ~~Central~~bond ~~Appalachia~~portfolio ~~operations~~by ~~during~~the ~~2018~~purchaser of Sands Hill Mining LLC as required by the sale agreement executed with the purchaser in November 2017.

~~Selling,~~Interest ~~General and Administrative~~Expense. ~~SG&A~~Interest expense for the year ended December 31, ~~2018~~2019 ~~increased~~decreased to $127.9 million as compared to $118.45 million for the year ended December 31, ~~2017~~2018. This decrease was primarily due to ~~bad~~the lower average outstanding debt ~~expense~~balance ofand ~~$0.9~~a ~~million~~lower effective ~~recognized~~interest inrate ~~2018~~on our Financing Agreement during 2019.

~~Interest~~Net ~~Expense~~Loss. ~~Interest~~Net ~~expense~~loss was approximately $47.6 million for the year ended December 31, ~~2018~~2019 ~~increased~~compared to a net loss of approximately $8.53 million asfor ~~compared~~the toyear $4ended December 31, 2018.0 ~~million~~ The net loss for the year ended December 31, ~~2017~~2019 was primarily the result of $26.0 ~~This~~million ~~increase~~in ~~was~~asset ~~primarily~~impairments. ~~due~~The toasset ~~the~~impairments ~~higher~~and ~~outstanding~~related ~~debt~~charges ~~balance~~included a $17.9 million impairment related to future development of Rhino Eastern and an $8.1 million impairment related to future development of Taylorville Mining LLC (please read —“Asset Impairments-2019” above for additional discussion). In addition to the ~~effective~~asset impairments, we also ~~interest~~experienced ~~rate~~a ondecrease in total revenue of $15.5 million primarily due to fewer tons of coal sold from our ~~new~~Central ~~Financing~~Appalachia mining ~~Agreement~~operation.

Net Loss. Net loss was approximately $16.0 million for the year ended December 31, 2018 compared to a net loss of approximately $20.6 million for the year ended December 31, 2017. Net loss for the year ended December 31, 2018 was primarily the result of a decrease in contracted sale prices for tons sold from our Pennyrile mine and an increase in the costs for freight and handling, contract services, equipment maintenance and diesel fuel at our Central Appalachia operations during 2018. The net loss for the year ended December 31, 2017 was primarily the result of $22.6 million in asset impairments. The asset impairments and related charges included an $0.8 million impairment of land owned by us in Mesa, Colorado included in our Western segment and a $21.8 million impairment of the Armstrong call option included in the Other category (please read —“Asset Impairments-2017” above for additional discussion).68

Adjusted EBITDA. Adjusted EBITDA from continuing operations decreased to $191.65 million for the year ended December 31, ~~2018~~2019 as ~~compared~~ compared to $2719.14 million for the year ended December 31, ~~2017~~2018. The decrease in Adjusted EBITDA ~~from continuing operations~~ during the year ended December 31, ~~2018~~ 2019 was primarily due to athe decrease in ~~net~~revenue ~~income~~discussed atabove ~~our Illinois Basin segment resulting from the decrease in the contracted sale prices for tons sold from our Pennyrile mine~~ and an increase in ~~operating~~labor costs ~~such~~across asall ~~freight and handling, contract services and diesel fuel at our Central Appalachia operations~~segments. Including net loss ~~income~~ from discontinued operations of approximately $151.89 million, which related to our ~~Sands~~Pennyrile ~~Hill~~Energy ~~Mining~~ operation sold in ~~November 2017~~September 2019, our net loss was $1899.8 5 million and Adjusted EBITDA was $26(5.37) million for the year ended December 31, ~~2017~~2019. WeIncluding ~~did~~net loss ~~not~~from ~~incur~~discontinued aoperations ~~gain~~of or$7.7 million, which also related to our Pennyrile Energy operation, our net loss ~~from~~was ~~discontinued~~$16.0 ~~operations~~million and Adjusted EBITDA was $19.6 million for the year ended December 31, 2018.

Segment Results

The following tables set forth certain information regarding our revenues, operating expenses, other income and expenses, and operational data by reportable segment for the years ended December 31, ~~2018~~2019 and ~~2017~~2018:

Central Appalachia	Year Ended December 31,					Increase/(Decrease)
	2018			2017		$			% *
	2019			2018		$			% *
	(in millions, except per ton data and %)
Coal revenues	$	~~139~~115.47		$	~~101~~139.84	$	37(23.67	)		36(17.90	%)
Freight and handling revenues		-			-		-			n/a
Other revenues		0.34			0.23		0.1			~~142~~20.12	%
Total revenues		~~139~~116.71			~~102~~139.07		37(23.76	)		37(16.09	%)
Coal revenues per ton	$	7479.7811		$	6974.6878	$	54.1033			75.38	%
Cost of operations (exclusive of depreciation, depletion and amortization shown separately below)		~~112~~109.15			78112.61		33(2.56	)		42(2.74	%)
Freight and handling costs		93.05			19.81		7(5.26	)		~~395~~(60.7	%)
Depreciation, depletion and amortization		8.71			78.7		1.(0.6	)		13(7.68	%)
Selling, general and administrative costs		0.92			0.29		(0.7	)		~~365~~(80.24	%)
Cost of operations per ton	$	60.16		$	53.76	$	6.40			11.9	%
Asset impairment and related charges		17.9			-		17.9			n/a
Net income from continuing operations		8.8			13.7		(4.9	)		(36.0	%)
Cost of operations per ton	$	74.89		$	60.16	$	14.73			24.5	%
Adjusted EBITDA from continuing operations		18.3			21.4		(3.1	)		(14.7	%)
Net income from continuing operations		(16.2	)		8.8		(25.0	)		(284.2	%)
Tons sold		1,864.2			1,461.6		402.6			27.5	%
Adjusted EBITDA from continuing operations		9.8			18.3		(8.5	)		(46.6	%)
Tons sold (in thousands except %)		1,462.1			1,864.1		(402.0	)		(21.6	%)

*	Percentages and per ton amounts are calculated based on actual amounts and not the rounded amounts presented in this table.

Tons of coal sold in our Central Appalachia segment ~~increased~~decreased by approximately 2721.56% to approximately 1.95 million tons for the year ended December 31, ~~2018~~2019 compared to the year ended December 31, ~~2017~~2018, primarily due to ana ~~increase~~decrease in demand for met and steam coal tons from this region.

Coal revenues ~~increased~~decreased by approximately $3723.67 million, or 3617.90%, to approximately $~~139~~115.47 million for the year ended December 31, ~~2018~~2019 from approximately $~~101~~139.84 million for the year ended December 31, ~~2017~~2018. This ~~increase~~decrease was primarily due to the ~~increase~~decrease in demand for met and steam coal tons sold from this region. Coal revenues per ton for our Central Appalachia segment increased by $54.1033, or 75.38%, to $7479.7811 per ton for the year ended December 31, ~~2018~~2019 as compared to $6974.6878 for the year ended December 31, ~~2017~~2018. This increase was primarily due to the increase in contracted sale prices for our met and steam coal from this region.

Cost of operations increased by $33.5 million, or 42.7%, to $112.1 million for the year ended December 31, 2018 from $78.6 million for the year ended December 31, 2017. Our cost of operations per ton of $60.16 for the year ended December 31, 2018 increased 11.9% compared to $53.76 per ton for the year ended December 31, 2017. Total cost of operations and cost of operations per ton increased period over period as we increased sales in this region during 2018 and experienced an increase in operating expenses such as diesel fuel, contract services and equipment maintenance compared to 2017.69

~~Total~~Cost ~~freight~~of ~~and~~operations ~~handling~~decreased ~~cost~~by ~~increased~~$2.6 million, or 2.4%, to $9109.05 million for the year ended December 31, ~~2018~~2019 from ~~approximately~~ $1112.81 million for ~~the~~ the year ended December 31, ~~2017~~2018. ~~The~~Our ~~increase~~cost inof ~~freight~~operations ~~and~~per ~~handling~~ton ~~costs~~of ~~was~~$74.89 ~~primarily~~for the ~~result~~year ofended ~~rail~~December ~~transportation~~31, ~~costs~~2019 increased 24.5% atcompared ~~our~~to ~~Central~~$60.16 ~~Appalachia~~per ~~operations~~ton asfor wethe ~~executed~~year ~~more~~ended ~~export~~December ~~coal~~31, ~~sales~~2018. inTotal ~~the~~cost ~~period~~of ~~that~~operations ~~required~~per uston toincreased ~~pay~~in ~~for~~Central ~~railroad~~Appalachia ~~transportation~~due to the ~~port~~decrease ofin ~~export.~~coal Wetons ~~also~~sold ~~incurred~~resulting ~~$1.1 million~~ in ~~demurrage~~fixed ~~charges~~costs ~~due~~being allocated to ~~rail~~fewer ~~transportation~~tons ~~constraints~~during 2019. We also experienced ~~that~~an ~~caused~~increase ~~shipments~~in tolabor beand ~~delayed~~maintenance tocosts ~~the~~in ~~port~~this ofregion ~~export~~during 2019 compared to 2018.

~~For~~Total ~~our~~freight ~~Central~~and ~~Appalachia~~handling ~~segment,~~cost ~~net~~decreased ~~income~~to ~~was~~$3.5 million for the year ended December 31, 2019 from approximately $89.81 million for the year ended December 31, 2018,. aThe decrease in freight and handling costs was primarily the result of ~~$4.9~~ ~~million~~fewer inexport ~~net~~sales ~~income~~that asrequire us ~~compared~~to pay railroad transportation to the ~~year~~port ~~ended~~of ~~December~~export ~~31,~~during ~~2017~~2019. ~~Net~~We ~~income~~also ~~was~~incurred ~~impacted~~$1.1 byin andemurrage ~~increase~~charges induring ~~the~~2018 ~~cost~~due ofto ~~operations~~rail ~~and~~transportation ~~freight~~constraints ~~and~~that ~~handling~~caused ~~charges~~shipments ~~discussed~~to ~~above~~be delayed to the port of export.

66For our Central Appalachia segment, net loss was approximately $16.2 million for the year ended December 31, 2019, a decrease of $25.0 million in net income as compared to the year ended December 31, 2018. The net loss was impacted by the $17.9 million asset impairment charge related to Rhino Eastern properties as discussed earlier and the decrease in coal revenues during 2019.

Central Appalachia Overview of Results by Product. Additional information for the Central Appalachia segment detailing the types of coal produced and sold, premium high-vol met coal and steam coal for the years ended December 31, ~~2018~~2019 and ~~2017~~2018, is presented below. Note that our Northern Appalachia, and Rhino Western ~~and Illinois Basin~~ segments currently produce and sell only steam coal.

(In thousands, except per ton data and %)	Year ended December 31, ~~2018~~2019		Year ended December 31, ~~2017~~2018		Increase (Decrease) %*
Met coal tons sold		~~873~~701.93		~~737~~873.39		18(19.58	%)
Steam coal tons sold		~~990~~760.28		~~724~~990.32		36(23.72	%)
Total tons sold		1,~~864~~462.1		1,~~461~~864.61		27(21.56	%)
Met coal revenue	$	8773,~~015~~284	$	6487,~~033~~015		35(15.98	%)
Steam coal revenue	$	5242,~~380~~384	$	3752,~~805~~380		38(19.61	%)
Total coal revenue	$	~~139~~115,~~395~~668	$	~~101~~139,~~838~~395		36(17.90	%)
Met coal revenues per ton	$	99104.5750	$	8699.8557		145.60	%
Steam coal revenues per ton	$	5255.9071	$	52.1990		15.43	%
Total coal revenues per ton	$	7479.7811	$	6974.6878		75.38	%
Met coal tons produced		~~515~~524.54		~~645~~515.85		~~(20~~1.27	%)
Steam coal tons produced		1,~~229~~079.37		~~904~~1,229.83		35(12.92	%)
Total tons produced		1,~~744~~604.81		1,~~550~~744.68		12(8.51	%)

*	Percentages and per ton amounts are calculated based on actual amounts and not the rounded amounts presented in this table.

Northern Appalachia	Year Ended December 31,						Increase/(Decrease)
	2018			2017			$			% *
	(in millions, except per ton data and %)
Coal revenues	$	18.2		$	15.9		$	2.3			15.0	%
Freight and handling revenues		-			-			-			n/a
Other revenues		2.2			1.3			0.9			71.2	%
Total revenues		20.4			17.2			3.2			19.2	%
Coal revenues per ton	$	43.05		$	41.58		$	1.47			3.5	%
Cost of operations (exclusive of depreciation, depletion and amortization shown separately below)		23.5			19.2			4.3			22.5	%
Freight and handling costs		-			-			-			n/a
Depreciation, depletion and amortization		1.2			1.0			0.2			23.5	%
Selling, general and administrative costs		0.2			-			0.2			186.3	%
Cost of operations per ton	$	55.48		$	50.34		$	5.14			10.2	%
Net loss from continuing operations		(4.4	)		(3.1	)		(1.3	)		42.9	%
Adjusted EBITDA from continuing operations		(3.1	)		(2.1	)		(1.0	)		46.0	%
Tons sold		423.6			381.3			42.3			11.1	%

Northern Appalachia	Year Ended December 31,						Increase/(Decrease)
	2019			2018			$			% *
	(in millions, except per ton data and %)

Coal revenues	$	23.8		$	18.2		$	5.6			30.5	%
Freight and handling revenues		-			-			-			n/a
Other revenues		1.6			2.2			(0.6	)		(25.8	%)
Total revenues		25.4			20.4			5.0			24.4	%
Coal revenues per ton	$	48.31		$	43.05		$	5.26			12.2	%
Cost of operations (exclusive of depreciation, depletion and amortization shown separately below)		30.8			23.5			7.3			31.2	%
Freight and handling costs		1.2			-			1.2			n/a
Depreciation, depletion and amortization		1.7			1.2			0.5			42.2	%
Selling, general and administrative costs		0.1			0.2			(0.1	)		(55.8	%)
Cost of operations per ton	$	62.63		$	55.48		$	7.15			12.9	%
Net (loss) from continuing operations		(8.4	)		(4.4	)		(4.0	)		89.3	%
Adjusted EBITDA from continuing operations		(6.7	)		(3.1	)		(3.6	)		115.7	%
Tons sold (in thousands except %)		492.6			423.6			69.0			16.3	%

*	Percentages and per ton amounts are calculated based on actual amounts and not the rounded amounts presented in this table.

For our Northern Appalachia segment, tons of coal sold increased by approximately 1116.13% for the year ended December 31, ~~2018~~2019 compared to the year ended December 31, ~~2017~~2018 as we experienced increased demand for coal from this region.

Coal revenues were approximately $1823.28 million for the year ended December 31, ~~2018~~2019, an increase of approximately $25.36 million, or 1530.05%, from approximately $1518.92 million for the year ended December 31, ~~2017~~2018. Coal revenues per ton increased by $15.4726 or 312.52% to $4348.0531 per ton for the year ended December 31, ~~2018~~2019, as compared to $4143.5805 for the year ended December 31, ~~2017~~2018, which was primarily due to an increase in contracted sale prices for tons sold from our Hopedale complex compared to the prior year.

67Cost of operations increased by $7.3 million, or 31.2%, to $30.8 million for the year ended December 31, 2019 from $23.5 million for the year ended December 31, 2018. Our cost of operations per ton was $62.63 for the year ended December 31, 2019, an increase of $7.15, or 12.9%, compared to $55.48 for the year ended December 31, 2018. The increase in total cost of operations and cost of operations per ton was primarily the result of adverse geological conditions we encountered during 2019. We also experienced an increase in operating expenses including labor, maintenance, roof support and contract services.

~~Cost~~Net ofloss ~~operations~~in ~~increased~~our byNorthern ~~$4.3~~Appalachia ~~million,~~segment orwas ~~22.5%, to~~ $238.54 million for the year ended December 31, ~~2018~~2019 ~~from~~compared ~~$19.2~~to ~~million~~net ~~for the~~loss ~~year ended December 31, 2017. Our cost~~ of ~~operations per ton was~~ $554.484 million for the year ended December 31, 2018,. anThe increase of ~~$5.14,~~in ornet ~~10.2%,~~loss ~~compared to $50.34~~ for the year ended December 31, ~~2017.~~2019 ~~The~~was ~~increase~~primarily due to the increase in ~~total~~the cost of operations ~~and~~partially ~~cost of~~offset ~~operations~~by ~~per~~the ~~ton~~increase ~~was~~in ~~primarily~~contracted ~~the~~sale ~~result~~prices of antons ~~increase~~sold incompared ~~maintenance~~to ~~costs~~the ~~and~~same ~~costs~~period in ~~for outside services~~2018.

Net loss in our Northern Appalachia segment was $4.4 million for the year ended December 31, 2018 compared to net loss of $3.1 million for the year ended December 31, 2017. The increase in net loss for the year ended December 31, 2018 was primarily due to the increase in the cost of operations partially offset by the increase in contracted prices of tons sold compared to the same period in 2017.71

Rhino Western	Year Ended December 31,				Increase/(Decrease)
	2018		2017		$			% *
	2019		2018		$			% *
	(in millions, except per ton data and %)
Coal revenues	$	3639.24	$	3536.42	$	03.82			29.10	%
Freight and handling revenues		-		-		-			n/a
Other revenues		-		-		-			n/a
Total revenues		3639.24		3536.42		03.82			28.19	%
Coal revenues per ton	$	3538.4010	$	3735.5440	$	(2.1470	)		~~(5.~~7.6	%)
Cost of operations (exclusive of depreciation, depletion and amortization shown separately below)		3029.58		2830.35		2(0.27	)		7(2.73	%)
Freight and handling costs		-		-		-			n/a
Depreciation, depletion and amortization		4.13		4.41		(0.32	)		~~(8.~~5.8	%)
Selling, general and administrative costs		0.1		0.1		-			59(44.9	%)
Cost of operations per ton	$	2928.8077	$	29.9680	$	(01.1603	)		(03.5	%)
Net income from continuing operations		1.4.5		1.74		~~(0.~~3.1	)		~~(17~~223.6	%)
Adjusted EBITDA from continuing operations		59.56		75.05		(14.51	)		~~(22~~75.1	%)
Tons sold		1,022.3		944.2		78.1			8.3	%
Tons sold (in thousands except %)		1,035.1		1,022.3		12.8			1.3	%

*	Percentages and per ton amounts are calculated based on actual amounts and not the rounded amounts presented in this table.

Tons of coal sold from our Rhino Western segment increased by approximately 81.3% for the year ended December 31, ~~2018~~2019 compared to ~~2017~~the ~~primarily~~same ~~due~~period ~~to an increase~~ in ~~demand for coal from this region~~2018.

Coal revenues increased by approximately $03.82 million, or 29.10%, to approximately $3639.24 million for the year ended December 31, ~~2018~~2019 from approximately $3536.42 million for the year ended December 31, ~~2017 primarily due to an increase in demand for tons sold from the Castle Valley mine during~~ 2018. Coal revenues per ton for our Rhino Western segment ~~decreased~~ increased by $2.1470 or 5.7.6% to $3538.4010 per ton for the year ended December 31, ~~2018~~2019 as compared to $3735.5440 per ton for the year ended December 31, ~~2017~~2018 due to ~~lower~~higher contracted sale prices.

Cost of operations ~~increased~~decreased by $20.27 million, or 72.73%, to $3029.58 million for the year ended December 31, ~~2018~~2019 from $2830.35 million for the year ended December 31, ~~2017~~2018. Our cost of operations per ton was $2928.8077 for the year ended December 31, ~~2018~~2019, a decrease of $01.1603, or 03.5%, compared to $29.9680 for the year ended December 31, ~~2017~~2018. Total cost of operations ~~increased~~and cost of operations per ton decreased slightly for the year ended December 31, ~~2018~~2019 compared to ~~2017~~2018 asprimarily wedue ~~saw~~to anlower ~~increase~~operating ~~in in demand for coal from this region~~costs. ~~The cost of operations per ton decreased slightly during 2018 compared to 2017.~~

68Net income in our Rhino Western segment was $4.5 million for the year ended December 31, 2019, compared to net income of $1.4 million for the year ended December 31, 2018. This increase in net income was primarily the result of higher contracted sale prices for tons sold at our Castle Valley operation.

Net income in our Rhino Western segment was $1.4 million for the year ended December 31, 2018, compared to net income of $1.7 million for the year ended December 31, 2017. This decrease in net income was primarily the result of lower contracted sale prices for tons sold at our Castle Valley operation.

Other	Year Ended December 31,						Increase/(Decrease)
	2019			2018			$			% *
	(in millions, except per ton data and %)

Coal revenues	$	-		$	-			n/a			n/a
Freight and handling revenues		-			-			n/a			n/a
Other revenues		0.1			0.2		$	(0.1	)		(70.2	%)
Total revenues		0.1			0.2			(0.1	)		(70.2	%)
Coal revenues per ton**		n/a			n/a			n/a			n/a
Cost of operations (exclusive of depreciation, depletion and amortization shown separately below)		(2.7	)		(2.5	)		(0.2	)		5.0	%
Freight and handling costs		-			-			-			n/a
Depreciation, depletion and amortization		0.4			0.4			-			(12.4	%)
Selling, general and administrative costs		14.5			11.4			3.1			27.5	%
Asset impairment and related charges		8.1			-			8.1			n/a
Cost of operations per ton**		n/a			n/a			n/a			n/a
Net (loss) from continuing operations		(27.5	)		(14.1	)		(13.4	)		95.7	%
Adjusted EBITDA from continuing operations		(11.2	)		(1.3	)		(9.9	)		759.2	%
Tons sold (in thousands except %)		n/a			n/a			n/a			n/a

Illinois Basin	Year Ended December 31,					Increase/(Decrease)
	2018			2017		$			% *
	(in millions, except per ton data and %)
Coal revenues	$	50.5		$	64.1	$	(13.6	)		(21.2	%)
Freight and handling revenues		-			-		-			n/a
Other revenues		-			-		-			n/a
Total revenues		50.5			64.1		(13.6	)		(21.2	%)
Coal revenues per ton	$	39.17		$	47.85	$	(8.68	)		(18.1	%)
Cost of operations (exclusive of depreciation, depletion and amortization shown separately below)		50.2			54.6		(4.4	)		(8.2	%)
Freight and handling costs		-			-		-			n/a
Depreciation, depletion and amortization		7.9			7.6		0.3			4.4	%
Selling, general and administrative costs		0.2			0.2		-			13.0	%
Cost of operations per ton	$	38.94		$	40.81	$	(1.87	)		(4.6	%)
Net (loss)/income from continuing operations		(7.7	)		1.7		(9.4	)		(543.4	%)
Adjusted EBITDA from continuing operations		0.2			9.3		(9.1	)		(97.6	%)
Tons sold		1,287.9			1,338.5		(50.6	)		(3.8	%)

* Percentages and per ton amounts are calculated based on actual amounts and not the rounded amounts presented in this table.

For our Illinois Basin segment, tons of coal sold decreased by approximately 3.8% for the year ended December 31, 2018 compared to the year ended December 31, 2017.

Coal revenues of approximately $50.5 million for the year ended December 31, 2018 decreased by approximately $13.6 million, or 21.2%, compared to $64.1 million for the year ended December 31, 2017. Coal revenues per ton for our Illinois Basin segment were $39.17 for the year ended December 31, 2018, a decrease of $8.68, or 18.1%, from $47.85 for the year ended December 31, 2017. The decrease in coal revenues and coal revenues per ton were primarily due to lower contracted prices for tons sold from our Pennyrile mine in western Kentucky.

Cost of operations was $50.2 million while cost of operations per ton was $38.94 for the year ended December 31, 2018, both of which related to our Pennyrile mining complex in western Kentucky. For the year ended December 31, 2017, cost of operations in our Illinois Basin segment was $54.6 million and cost of operations per ton was $40.81. The decrease in cost of operations and cost of operations per ton for the year ended December 31, 2018 was primarily the result of fewer tons being produced and lower operating costs at our Pennyrile mining complex during the year ended December 31, 2018.

For our Illinois Basin segment, we generated a net loss of $7.7 million for the year ended December 31, 2018 compared to net income of $1.7 million for the year ended December 31, 2017. The net loss was primarily the result of a decrease in the contracted sale prices for tons sold during 2018 compared to 2017.

Other	Year Ended December 31,						Increase/(Decrease)
	2018			2017			$			% *
	(in millions, except per ton data and %)
Coal revenues		n/a			n/a			n/a			n/a
Freight and handling revenues		n/a			n/a			n/a			n/a
Other revenues	$	0.2		$	-		$	0.2			339.3	%
Total revenues		0.2			-			0.2			339.3	%
Coal revenues per ton**					n/a			n/a			n/a
Cost of operations (exclusive of depreciation, depletion and amortization shown separately below)		(2.7	)		(2.2	)		(0.5	)		22.9	%
Freight and handling costs		-			-			-			n/a
Depreciation, depletion and amortization		0.4			0.4			-			(1.7	%)
Selling, general and administrative costs		11.4			10.9			0.5			4.9	%
Cost of operations per ton**		n/a			n/a			n/a			n/a
Net loss from continuing operations		(14.1	)		(34.6	)		20.5			(59.4	%)
Adjusted EBITDA from continuing operations		(1.3	)		(8.5	)		7.2			(84.6	%)
Tons sold		n/a			n/a			n/a			n/a

*	Percentages and per ton amounts are calculated based on actual amounts and not the rounded amounts presented in this table.

**	The Other category includes results for our ancillary businesses. The activities performed by these ancillary businesses do not directly relate to coal production. As a result, coal revenues and coal revenues per ton are not presented for the Other category. Cost of operations presented for our Other category includes costs incurred by our ancillary businesses. As a result, cost per ton measurements are not presented for this category.

~~Other revenues for our Other category were $0.2 million for the year ended December 31, 2018 compared to approximately $41,000 for the year ended December 31, 2017.~~72

~~For~~Other ~~the~~revenues for our Other category, wewere ~~had net loss from continuing operations of~~ $140.1 million for the year ended December 31, ~~2018~~2019 as compared to ~~net~~approximately ~~loss from continuing operations of~~ $340.62 million for the year ended December 31, ~~2017. The net loss for the year ended December 31,~~ 2018 ~~was impacted by an increase of approximately $4~~.5 million in interest expense. Net loss for the year ended December 31, 2017 was primarily attributable to the $21.8 million asset impairment recorded for the Armstrong call option as discussed earlier in this section.

70For the Other category, we had net loss from continuing operations of $27.5 million for the year ended December 31, 2019 as compared to net loss from continuing operations of $14.1 million for the year ended December 31, 2018. Net loss for the year ended December 31, 2019 was impacted by the $8.1 million asset impairment charge related to Taylorville Mining LLC and the $2.0 million SG&A expense discussed above.

Reconciliation of Adjusted EBITDA

The following tables present reconciliations of Adjusted EBITDA to the most directly comparable GAAP financial measures for each of the periods indicated. Adjusted EBITDA excludes the effect of certain non-cash and/or non-recurring items. Adjusted EBITDA is used by management primarily as a measure of our segments’ operating performance. Adjusted EBITDA should not be considered an alternative to net income, income from operations, cash flows from operating activities or any other measure of financial performance or liquidity presented in accordance with GAAP. Because not all companies calculate Adjusted EBITDA identically, our calculation may not be comparable to similarly titled measures of other companies.

	Central			Northern			Rhino		Illinois
Year ended December 31, 2018	Appalachia			Appalachia			Western		Basin			Other			Total
Year ended December 31, 2019	Appalachia			Appalachia			Western		Basin			Other			Total
	(in millions)
Net income/(loss) from continuing operations	$	8.8		$	(4.4	)	$	1.4	$	(7.7	)	$	(14.1	)	$	(16.0	)
Net income/(loss)	$	(16.2	)	$	(8.4	)	$	4.5	$	-		$	(27.5	)	$	(47.6	)
Plus:
DD&A		8.71			1.27			4.13		~~7.9~~-			0.4			2214.35
Interest expense		-			-			-		-			87.59			87.59
EBITDA from continuing operations†	$	17(8.51	)	$	(36.27	)	$	58.58	$	~~0.2~~-		$	(519.2	)	$	14(25.82	)
Plus: Provision for doubtful accounts (1)		0.8			0.1			-		-			-			0.9
Plus: Non-cash asset impairment (1)		17.9			-			-		-			8.1			26.0
Plus: Cumulative effect from adoption of ASU 2016-01 (2)		-			-			-		-			3.7			3.7
Plus: Loss from sale of non-core assets (2)		-			-			0.8		-			-			0.8
Plus: Mark-to-market adjustment -unrealized loss		-			-			-		-			0.2			0.2
Adjusted EBITDA from continuing operations		9.8			(6.7	)		9.6		-			(11.2	)		1.5
Adjusted EBITDA from continuing operations†		18.3			(3.1	)		5.5		0.2			(1.3	)		19.6
EBITDA from discontinued operations		-			-			-		(45.9	)		-			(45.9	)
EBITDA from discontinued operations		-			-			-		-			-			-
Plus: Loss on impairment of assets (3)		-			-			-		38.7			-			38.7
Adjusted EBITDA †	$	18.3		$	(3.1	)	$	5.5	$	0.2		$	(1.3	)	$	19.6
Adjusted EBITDA	$	9.8		$	(6.7	)	$	9.6	$	(7.2	)	$	(11.2	)	$	(5.7	)

	Central		Northern			Rhino		Illinois
Year ended December 31, 2017	Appalachia		Appalachia			Western		Basin		Other			Total
Year ended December 31, 2018	Appalachia		Appalachia			Western		Basin		Other			Total
	(in millions)
Net (loss)/income from continuing operations	$	13.7	$	(3.1	)	$	1.7	$	1.7	$	(34.6	)	$	(20.6	)
Net (loss)/income	$	8.8	$	(4.4	)	$	1.4	$	-	$	(14.1	)	$	(8.3	)
Plus:														-
DD&A		78.7		1.02			4.41		~~7.6~~-		0.4			2114.14
Interest expense		-		-			-		-		48.05			48.05
EBITDA from continuing operations†	$	2117.45	$	(23.12	)	$	65.15	$	~~9.3~~-	$	(305.2	)	$	414.56
Plus: Non-cash asset impairment and other non-cash charges (3)		-		-			0.8		-		21.8			22.6
Plus: Provision for doubtful accounts (4)		0.8		0.1			-		-		-			0.9
Adjusted EBITDA from continuing operations†		21.4		(2.1	)		6.9		9.3		(8.4	)		27.1
Plus: Cumulative effect from adoption of ASU 2016-01 (5)		-		-			-		-		3.7			3.7
EBITDA from discontinued operations		-		(0.8	)		-		-		-			(0.8	)
Plus: Mark-to-market adjustment -unrealized loss		-		-			-		-		0.2			0.2
Adjusted EBITDA †	$	21.4	$	(2.9	)	$	6.9	$	9.3	$	(8.4	)	$	26.3
Adjusted EBITDA from continuing operations†	$	18.3	$	(3.1	)	$	5.5	$	-	$	(1.3	)	$	19.4
EBITDA from discontinued operations		-		-			-		0.2		-			0.2
Adjusted EBITDA	$	18.3	$	(3.1	)	$	5.5	$	0.2	$	(1.3	)	$	19.6

7173

	For the Year Ended December 31,
	2018			2017
	2019			2018
	(in millions)
Reconciliation of net cash to Adjusted EBITDA provided by operating activities:
Net cash (used in)/provided by operating activities	$	(11.4	)	$	18.6
Net cash provided by operating activities	$	18.6		$	14.6
Plus:
Increase in net operating assets		-			12.1
Gain on sale of assets		6.7			3.4
Gain on sale of assets		3.4			-
Interest expense		7.9			8.5
Gain on disposal of business		-			3.2
Decrease in deferred revenue		-			-
Interest expense		8.5			4.0
Equity in net income of unconsolidated affiliates		-			0.1
Less:
Decrease in net operating assets		104.21			-10.2
Mark-to-market adjustment – unrealized loss		0.2			-
Mark-to-market adjustment - unrealized loss		-			0.2
Amortization of advance royalties		01.6			10.16
Amortization of debt discount		0.4			-0.4
Amortization of debt issuance costs		12.80			1.58
Increase in provision for doubtful accounts		0.9			0.1
Increase in provision for doubtful accounts (4)		-			0.9
Equity-based compensation		0.2			0.3
Loss on sale of assets		-			-
Loss on asset impairments		-			22.6
Loss on impairment of assets		64.7			-
Loss on retirement of advance royalties		0.13			0.1
Accretion on asset retirement obligations		1.3			1.5
Equity based compensation		-			0.2
EBITDA		14.8			6.8
Accretion on asset retirement obligations		1.3			1.3
Plus: Non-cash bad debt expense (1)		0.9			0.1
EBITDA†		(71.2	)		14.8
Plus: Non-cash asset impairment and other non-cash charges (3)		-			22.6
Plus: Loss from sale of non-core assets (2)		0.8
Plus: Cumulative effect from adoption of ASU 2016-01 (2)		3.7			-
Plus: Cumulative effect from adoption of ASU 2016-01 (5)		-			3.7
Plus: Mark-to-market adjustment -unrealized loss		0.2			-
Plus: Non-cash bad debt expense		-			0.9
Less: Gain on disposal of business (4)		-			(3.2	)
Plus: Mark-to-market adjustment -unrealized loss		-			0.2
Adjusted EBITDA		19.6			26.3
Plus: Loss on asset impairments (1)(3)		64.7			-
Less: EBITDA from discontinued operations		-			(0.8	)
Adjusted EBITDA		(5.7	)		19.6
Adjusted EBITDA from continuing operations	$	19.6		$	27.1
Less: Adjusted EBITDA from discontinued operations		(7.2	)		0.2
Adjusted EBITDA from continuing operations	$	1.5		$	19.4

†	Calculated based on actual amounts and not the rounded amounts presented in this table.
(1)	During the year ended December 31, 2018, we recorded provisions for doubtful accounts of approximately $0.9 million, which primarily related to a small number of customers in Central Appalachia.
*	Totals may not foot due to rounding.
(2)	During the year ended December 31, 2018, the gain recognized from the sales of our TUSK stock was impacted by the adoption of ASU 2016-01, which resulted in $3.7 million of economic benefit being reclassified to equity from Other Comprehensive Income instead of being recognized in net income.
(1)	During the year ended December 31, 2019, we recorded asset impairment charges of $26.0 million, including a $17.9 million impairment related to future development of Rhino Eastern and $8.1 million related to the future development of Taylorville Mining LLC.
(3)	During the year ended December 31, 2017, we recorded asset impairment charges of $22.6 million, including an $0.8 million impairment on land that we own in Mesa County, Colorado and a $21.8 million impairment charge related to the call option received from a third party to acquire substantially of the outstanding common stock of Armstrong Energy, Inc. as discussed earlier.
(2)	During the year ended December 31, 2019, we sold parcels of land owned in western Colorado for proceeds less than our carrying value of the land that resulted in losses of approximately $0.8 million. This land is a non-core asset that we chose to monetize despite the loss incurred.
(4)	On November 7, 2017, we closed an agreement with a third party to transfer 100% of the membership interests and related assets and liabilities in Sands Hill Mining LLC as discussed earlier. We recognized a non-cash gain of $3.2 million from the sale of Sands Hill Mining LLC since the third party assumed the reclamation obligations associated with this operation.
(3)	We recorded an impairment loss of $38.7 million associated with the sale of our Pennyrile assets for year ended December 31, 2019. The impairment loss of $38.7 million is recorded in discontinued operations for the year ended December 31, 2019.
	We believe that the isolation and presentation of these specific items to arrive at Adjusted EBITDA is useful because it enhances investors’ understanding of how we assess the performance of our business. We believe the adjustment of these items provides investors with additional information that they can utilize in evaluating our performance. Additionally, we believe the isolation of these items provides investors with enhanced comparability to prior and future periods of our operating results.

(4)	During the year ended December 31, 2018, we recorded provisions for doubtful accounts of approximately $0.9 million, which primarily related to a small number of customers in Central Appalachia.

(5)	During the year ended December 31, 2018, the gain recognized from the sales of our TUSK stock was impacted by the adoption of ASU 2016-01, which resulted in $3.7 million of economic benefit being reclassified to equity from Other Comprehensive Income instead of being recognized in net income.

	We believe that the isolation and presentation of these specific items to arrive at Adjusted EBITDA is useful because it enhances investors’ understanding of how we assess the performance of our business. We believe the adjustment of these items provide investors with additional information that they can utilize in evaluating our performance. Additionally, we believe the isolation of these items provide investors with enhanced comparability to prior and future periods of our operating results.

Liquidity and Capital Resources

Liquidity

On December 27, 2017, we entered into a Financing Agreement, which provides us with a multi-draw loan in the original aggregate principal amount of $80 million. The total principal amount is divided into a $40 million commitment, the conditions for which were satisfied at the execution of the ~~financing~~Financing ~~agreement~~Agreement and ana ~~additional~~ $3540 million additional commitment that iswas contingent upon the satisfaction of certain conditions precedent specified in the ~~financing~~Financing ~~agreement~~Agreement. As of December 31, 2019, we had utilized $15 million of the $40 million additional commitment, which results in $25 million of the additional commitment remaining. We used approximately $17.3 million of the initial Financing Agreement net proceeds ~~thereof~~ to repay all amounts outstanding and terminate the ~~Amended~~amended and ~~Restated~~restated credit ~~Credit~~agreement ~~Agreement~~ with PNC Bank, National Association, as Administrative Agent. The Financing Agreement ~~terminates~~initially onhad a termination date of December 27, 2020., ~~For~~which ~~more~~was ~~information~~amended ~~about~~to ~~our~~December ~~financing agreement~~27, ~~please~~2022 ~~read~~per “—the fifth amendment to the Financing Agreement” discussed further below.

Our business is capital intensive and requires substantial capital expenditures for purchasing, upgrading and maintaining equipment used in developing and mining our reserves, as well as complying with applicable environmental and mine safety laws and regulations. Our principal liquidity requirements are to finance current operations, fund capital expenditures, including acquisitions from time to time, and service our debt. Historically, our sources of liquidity included cash generated by our operations, cash available on our balance sheet and issuances of equity securities. Our ability to access the capital markets on economic terms in the future will be affected by general economic conditions, the domestic and global financial markets, our operational and financial performance, the value and performance of our equity securities, prevailing commodity prices and other macroeconomic factors outside of our control. Failure to maintain financing or to generate sufficient cash flow from operations could cause us to significantly reduce our spending and to alter our short- or long-term business plan. We may also be required to consider other options, such as selling assets or merger opportunities, and depending on the urgency of our liquidity constraints, we may be required to pursue such an option at an inopportune time.

73Beginning in the later part of the third quarter of 2019, we have experienced significantly weaker market demand and have seen prices move lower for the qualities of met and steam coal we produce. This downward price trend has been exacerbated by the recent coronavirus pandemic. In response to this reduced demand and to the significant health threats to our employees, on March 20, 2020, we temporarily idled production at several of our mines. We will continue to monitor conditions to ensure the health and welfare of our employees. We do not expect the idling of the coal production activities will affect our ability to fulfill current customer commitments, as loading and shipping crews will remain in place to ship coal from existing inventories.

WeIf we continue to experience weak demand and prices continue to ~~take~~lower ~~measures~~for our met and steam coal, ~~including~~we may not be able to continue to give the required ~~suspension~~representations or meet all of ~~cash~~the ~~distributions~~covenants onand restrictions included in our ~~common~~Financing ~~and~~Agreement. ~~subordinated~~If ~~units~~we violate any of the covenants or restrictions in our Financing Agreement, including the fixed-charge coverage ratio, some or all of our indebtedness may become immediately due and ~~cost~~payable, and ~~productivity~~our Lenders may not be willing to make any loans under the ~~improvements,~~additional commitment available under our Financing Agreement. If we are unable to ~~enhance~~give ~~and~~a ~~preserve~~required representation or we violate a covenant or restriction, then we will need a waiver from our ~~liquidity~~Lenders sounder ~~that~~our Financing Agreement, or they may declare an event of default and, after applicable specified cure periods, all amounts outstanding under the Financing Agreement would become immediately due and payable. Although we ~~can~~believe ~~fund~~our Lenders are well secured under the terms of our Financing ~~ongoing~~Agreement, there is no assurance that the Lenders would agree to any such waiver. Failure to obtain financing or to generate sufficient cash flow from operations could cause us to further curtail our operations and ~~necessary~~reduce ~~capital~~spending ~~expenditures~~ and ~~meet~~alter our business plan. We are currently considering alternatives to address our ~~financial~~liquidity ~~commitments~~and balance sheet issues, such as selling additional assets or seeking merger opportunities, and depending ~~debt~~on ~~service~~the ~~obligations~~urgency of our liquidity constraints, we may be required to pursue such an option at an inopportune time.

We evaluated our Financing Agreement at December 31, 2019 to determine whether the debt liability should be classified as a long-term or current liability on our consolidated statements of financial position. We determined that we were in violation of certain debt covenants in the financing agreement as of December 31, 2019 and the Lenders were unwilling to grant a waiver to us for these events of default as of the filing date of this Form 10-K. The Financing Agreement contains negative covenants that restrict our ability to, among other things, permit the trailing nine month fixed charge coverage ratio of us and our subsidiaries to be less than 1.20 to 1.00. The Financing Agreement also requires us to receive an annual unqualified audit opinion from our external audit firm that does not include an emphasis paragraph on our ability to continue as a going concern. As of December 31, 2019, our fixed charge coverage ratio was less than 1.20 to 1.00 and our annual report on Form 10-K includes an audit opinion from our external auditors that includes an emphasis paragraph regarding our ability to continue as a going concern. Based upon these covenant violations, our debt liability is currently callable by the Lenders and we reclassified the debt liability as current.

Debt issuance costs related to the debt liability have also been reclassified to current. However, since we are currently in negotiations with our Lenders, we have not changed the amortization period of these costs. Included in debt costs are the exit fees described further in Note 11, which absent a waiver, are also callable with the accompanying debt as of December 31, 2019. (Please read Note 11 for additional discussion of our financing agreement).

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

Cash Flows

Net cash ~~provided~~used byin operating activities was $1811.64 million for the year ended December 31, ~~2018~~2019 as compared tonet cash provided by operating activities of $1418.6 million for the year ended December 31, ~~2017~~2018. This ~~increase~~decrease in cash provided by operating activities was primarily the result of ~~favorable~~ higher net loss and negative working capital changes, including ~~the~~increases ~~benefit~~in ~~of lowering~~ our inventory ~~with~~during ~~increased~~the ~~coal~~fourth ~~sales~~quarter of ~~and~~2019 ~~collections~~due ofto the ~~related accounts~~weak ~~receivable~~coal ~~balances~~market conditions.

Net cash ~~used~~provided inby investing activities was $71.6 million for the year ended December 31, ~~2018~~2019 as compared to net cash used in investing activities of $187.56 million for the year ended December 31, ~~2017~~2018. The decrease in cash used in investing activities was primarily due to ~~proceeds~~lower ~~received from the sales of Mammoth Inc. shares during 2018, partially offset by higher~~ capital expenditures in ~~2018~~ 2019 compared to ~~2017~~2018.

Net cash ~~used~~provided inby financing activities was $263.07 million for the year ended December 31, ~~2018~~2019, which was primarily attributable to ~~payments~~to onproceeds from our Financing Agreement, and other debt partially offset by payment of the distribution on the Series A preferred units and ~~deposits~~repayments ~~required~~of ~~for~~other ~~our workers’ compensation and surety programs~~debt. Net cash ~~provided~~used byin financing activities was $2526.0 million for the year ended December 31, ~~2017~~2018, which was primarily ~~due~~attributable to ~~proceeds~~payments ~~from~~on debt, deposits paid on our ~~Financing~~workers’ ~~Agreement~~compensation and surety bond programs and payment of the distribution on the Series A preferred units partially offset by ~~repayment~~proceeds offrom our ~~former revolving~~Financing ~~credit facility~~Agreement.

Capital Expenditures

Our mining operations require investments to expand, upgrade or enhance existing operations and to meet environmental and safety regulations. Maintenance capital expenditures are those capital expenditures required to maintain our long-term operating capacity. For example, maintenance capital expenditures include expenditures associated with the replacement of equipment and coal reserves, whether through the expansion of an existing mine or the acquisition or development of new reserves, to the extent such expenditures are made to maintain our long-term operating capacity. Expansion capital expenditures are those capital expenditures that we expect will increase our operating capacity over the long term. Examples of expansion capital expenditures include the acquisition of reserves, acquisition of equipment for a new mine or the expansion of an existing mine to the extent such expenditures are expected to expand our long-term operating capacity.

Actual maintenance capital expenditures for the year ended December 31, ~~2018~~2019 were approximately $147.28 million. These amounts were primarily used to rebuild, repair or replace older mining equipment. Expansion capital expenditures for the year ended December 31, ~~2018~~2019 were approximately $106.23 million, which were primarily related to ~~the~~expenditures ~~purchase of additional equipment to expand production~~ at ~~one~~ of our ~~Central~~new ~~Appalachia~~Jewell Valley mines. For the year ended December 31, ~~2019~~2020, we have budgeted $1310 million to $1612 million for maintenance capital expenditures and $21 million to $42 million for expansion capital expenditures.

Financing Agreement

On December 27, 2017, we entered into a Financing Agreement ~~with Cortland Capital Market Services LLC~~, ~~as Collateral Agent and Administrative agent, CB Agent Services LLC, as Origination Agent and the parties identified as Lenders therein,~~ pursuant to which the Lenders ~~have~~ agreed to provide us with a multi-draw term loan in the original aggregate principal amount of $80 million, subject to the terms and conditions set forth in the Financing Agreement. The total principal amount is divided into a $40 million commitment, the conditions ~~for~~ of which were satisfied at the execution of the Financing Agreement ~~and~~(the an“Effective ~~additional~~Date Term Loan Commitment”) and a $3540 million ~~commitment~~additional commitment that iswas contingent upon the satisfaction of certain conditions precedent specified in the Financing Agreement (“Delayed Draw Term Loan Commitment”). As of December 31, 2019, we have utilized $15 million of the $40 million additional commitment, which results in $25 million of the additional commitment remaining. Loans made pursuant to the Financing Agreement ~~will~~ beare secured by substantially all of our assets. The Financing Agreement ~~terminates~~originally onhad a termination date of December 27, 2020, which was amended to December 27, 2022 per the fifth amendment to the Financing Agreement discussed further below.

74Loans made pursuant to the Financing Agreement are, at our option, either “Reference Rate Loans” or “LIBOR Rate Loans.” Reference Rate Loans bear interest at the greatest of (a) 4.25% per annum, (b) the Federal Funds Rate plus 0.50% per annum, (c) the LIBOR Rate (calculated on a one-month basis) plus 1.00% per annum or (d) the Prime Rate (as published in the Wall Street Journal) or if no such rate is published, the interest rate published by the Federal Reserve Board as the “bank prime loan” rate or similar rate quoted therein, in each case, plus an applicable margin of 9.00% per annum (or 12.00% per annum if we have elected to capitalize an interest payment pursuant to the PIK Option, as described below). LIBOR Rate Loans bear interest at the greater of (x) the LIBOR for such interest period divided by 100% minus the maximum percentage prescribed by the Federal Reserve for determining the reserve requirements in effect with respect to eurocurrency liabilities for any Lender, if any, and (y) 1.00%, in each case, plus 10.00% per annum (or 13.00% per annum if we have elected to capitalize an interest payment pursuant to the PIK Option). Interest payments are due on a monthly basis for Reference Rate Loans and one-, two- or three-month periods, at our option, for LIBOR Rate Loans. If there is no event of default occurring or continuing, we may elect to defer payment on interest accruing at 6.00% per annum by capitalizing and adding such interest payment to the principal amount of the applicable term loan (the “PIK Option”).

Loans made pursuant to the Financing Agreement will, at our option, either be “Reference Rate Loans” or “LIBOR Rate Loans.” Reference Rate Loans bear interest at the greatest of (a) 4.25% per annum, (b) the Federal Funds Rate plus 0.50% per annum, (c) the LIBOR Rate (calculated on a one-month basis) plus 1.00% per annum or (d) the Prime Rate (as published in the Wall Street Journal) or if no such rate is published, the interest rate published by the Federal Reserve Board as the “bank prime loan” rate or similar rate quoted therein, in each case, plus an applicable margin of 9.00% per annum (or 12.00% per annum if we have elected to capitalize an interest payment pursuant to the PIK Option, as described below). LIBOR Rate Loans bear interest at the greater of (x) the LIBOR for such interest period divided by 100% minus the maximum percentage prescribed by the Federal Reserve for determining the reserve requirements in effect with respect to eurocurrency liabilities for any Lender, if any, and (y) 1.00%, in each case, plus 10.00% per annum (or 13.00% per annum if we have elected to capitalize an interest payment pursuant to the PIK Option). Interest payments are due on a monthly basis for Reference Rate Loans and one-, two- or three-month periods, at our option, for LIBOR Rate Loans. If there is no event of default occurring or continuing, we may elect to defer payment on interest accruing at 6.00% per annum by capitalizing and adding such interest payment to the principal amount of the applicable term loan (the “PIK Option”).77

Commencing December 31, 2018, the principal for each loan made under the Financing Agreement will be payable on a quarterly basis in an amount equal to $375,000 per quarter, with all remaining unpaid principal and accrued and unpaid interest originally due on December 27, 2020 (see discussion of fifth amendment below). In addition, we must make certain prepayments over the term of any loans outstanding, including: (i) the payment of 25% of Excess Cash Flow (as that term is defined in the Financing Agreement) for each fiscal year, commencing with respect to the year ending December 31, 2019, (ii) subject to certain exceptions, the payment of 100% of the net cash proceeds from the dispositions of certain assets, the incurrence of certain indebtedness or receipts of cash outside of the ordinary course of business, and (iii) the payment of the excess of the outstanding principal amount of term loans outstanding over the amount of the Collateral Coverage Amount (as that term is defined in the Financing Agreement). In addition, the Lenders are entitled to (i) certain fees, including 1.50% per annum of the unused Delayed Draw Term Loan Commitment for as long as such commitment exists, (ii) for the 12-month period following the execution of the Financing Agreement, a make-whole amount equal to the interest and unused Delayed Draw Term Loan Commitment fees that would have been payable but for the occurrence of certain events, including among others, bankruptcy proceedings or the termination of the Financing Agreement by us, and (iii) audit and collateral monitoring fees and origination and exit fees.

The Financing Agreement requires us to comply with several affirmative covenants at any time loans are outstanding, including, among others: (i) the requirement to deliver monthly, quarterly and annual financial statements, (ii) the requirement to periodically deliver certificates indicating, among other things, (a) compliance with terms of Financing Agreement and ancillary loan documents, (b) inventory, accounts payable, sales and production numbers, (c) the calculation of the Collateral Coverage Amount (as that term is defined in the Financing Agreement), (d) projections for the business and (e) coal reserve amounts; (iiiii) the requirement to notify the Administrative Agent of certain events, including events of default under the Financing Agreement, dispositions, entry into material contracts, (~~iii~~iv) the requirement to maintain insurance, obtain permits, and comply with environmental and ~~reclamation~~ reclamation laws (ivv) the requirement to sell up to $5.0 million of shares in Mammoth ~~Energy Securities,~~ Inc. and use the net proceeds therefrom to prepay outstanding term loans and (vvi) establish and maintain cash management services and establish a cash management account and deliver a control agreement with respect to such account to the Collateral Agent. The Financing Agreement also contains negative covenants that restrict our ability to, among other things: (i) incur liens or additional indebtedness or make investments or restricted payments, (ii) liquidate or merge with another entity, or dispose of assets, (iii) change the nature of our respective businesses; (~~iii~~iv) make capital expenditures in excess, or, with respect to maintenance capital expenditures, lower than, specified amounts, (ivv) incur restrictions on the payment of dividends, (vvi) prepay or modify the terms of other indebtedness, (vivii) permit the Collateral Coverage Amount to be less than the outstanding principal amount of the loans outstanding under the Financing Agreement or (~~vii~~viii) permit the trailing six month Fixed Charge Coverage Ratio to be less than 1.20 to 1.00 commencing with the six-month period ending June 30, 2018.

The Financing Agreement contains customary events of default, following which the Collateral Agent may, at the request of ~~lenders~~Lenders, terminate or reduce all commitments and accelerate the maturity of all outstanding loans to become due and payable immediately together with accrued and unpaid interest thereon and exercise any such other rights as specified under the Financing Agreement and ancillary loan documents.

On April 17, 2018, we amended our Financing Agreement to allow for certain activities, including a sale leaseback of certain pieces of equipment, the extension of the due date for lease consents required under the Financing Agreement to June 30, 2018 and the distribution to holders of the Series A preferred units of $6.0 million (accrued in the consolidated financial statements at December 31, 2017). Additionally, the amendments provided that the Partnership could sell additional shares of Mammoth Inc. stock and retain 50% of the proceeds with the other 50% used to reduce debt. ~~The~~We ~~Partnership~~ reduced ~~its~~our outstanding debt by $3.4 million with proceeds from the sale of Mammoth Inc. stock in the second quarter of 2018.

75On July 27, 2018, we entered into a consent $5.0 million loan from the Delayed Draw Term Loan Commitment, which was repaid in full on October 26, 2018 pursuant to the terms of the consent. The consent also included a waiver of the requirements relating to the use of proceeds of any sale of the shares of Mammoth Inc. set forth in the consent to the Financing Agreement, dated as of April 17, 2018 and also waived any Event of Default that arose or would otherwise arise under the Financing Agreement for failing to comply with the Fixed Charge Coverage Ratio for the six months ended June 30, 2018.

On ~~July~~November 278, 2018, we entered into a consent with our Lenders related to the Financing Agreement. The consent included the ~~lenders~~Lenders’ agreement to ~~make~~waive a $5 million loan from the Delayed Draw Term Loan Commitment, which was repaid in full on October 26, 2018 pursuant to the terms of the consent. The consent also included a waiver of the requirements relating to the use of proceeds of any ~~sale of the shares of Mammoth Inc. set forth in the consent to the Financing Agreement, dated as of April 17, 2018 and also waived any~~ Event of Default that arose or would otherwise arise under the Financing Agreement for failing to comply with the Fixed Charge Coverage Ratio for the six months ended ~~June~~September 30, 2018.

On November 8, 2018, we entered into a consent with our Lenders related to the Financing Agreement. The consent includes the lenders agreement to waive any Event of Default that arose or would otherwise arise under the Financing Agreement for failing to comply with the Fixed Charge Coverage Ratio for the six months ended September 30, 2018.78

On December 20, 2018, we entered into a limited consent and Waiver to the Financing Agreement. The Waiver ~~relates~~related to ~~our~~ sales of ~~certain~~ certain real property in Western Colorado, the net proceeds of which ~~are~~were required to be used to reduce our debt under the Financing Agreement. As of the date of the Waiver, we had sold 9 individual lots in smaller transactions. Rather than transmitting net proceeds ~~with~~ with respect to each individual transaction, we agreed with the Lenders in principle to delay repayment until an aggregate payment could be made at the end of 2018. On December 18, 2018, we used the sale proceeds of approximately $379,000 to reduce the debt. The Waiver (i) contains a ratification by the Lenders of the sale of the individual lots to date and waives the associated technical defaults under the Financing Agreement for not making immediate payments of net proceeds therefrom, (ii) permits the sale of certain specified additional lots and (iii) subject to Lender consent, permits the sale of other lots on a going forward basis. The net proceeds of future sales will be held by us until a later date to be determined by the Lenders.

On February 13, 2019, we entered into a second amendment to the Financing Agreement. The Amendment ~~provides~~provided the Lender’s consent for us to pay a one-time cash distribution on February 14, 2019 to the Series A Preferred Unitholders not to exceed approximately $3.2 million. The Amendment ~~allows~~allowed us to sell our remaining shares of Mammoth Energy Services, Inc. and utilize the proceeds ~~for~~ for payment of the one-time cash distribution to the Series A Preferred Unitholders and ~~waives~~waived the requirement to use such proceeds to prepay the outstanding principal amount outstanding under the Financing Agreement. The Amendment also ~~waives~~waived any Event of Default that has or would otherwise arise under Section 9.01(c) of the Financing Agreement solely by reason of us failing to comply with the Fixed Charge Coverage Ratio covenant in Section 7.03(b) of the Financing Agreement for the fiscal quarter ending December 31, 2018. The Amendment ~~includes~~included an amendment fee of approximately $0.6 million payable by us on May 13, 2019 and an exit fee equal to 1% of the principal amount of the term loans made under the Financing Agreement that is payable on the earliest of (w) the final maturity date of the Financing Agreement, (x) the termination date of the Financing Agreement, (y) the acceleration of the obligations under the Financing Agreement for any reason, including, without limitation, acceleration in accordance with Section 9.01 of the Financing Agreement, including as a result of the commencement of an insolvency proceeding and (z) the date of any refinancing of the term loan under the Financing Agreement. The Amendment ~~amends~~amended the definition of the Make-Whole Amount under the Financing Agreement to extend the date of the Make-Whole Amount period to December 31, 2019.

AtOn ~~December~~May 318, ~~2018~~2019, ~~$29~~we entered into Third Amendment to the Financing Agreement.0 ~~million~~The ~~was~~Third ~~outstanding~~Amendment ~~under~~included the ~~financing~~Lender’s agreement to atwaive aany ~~variable~~Event ~~interest~~of ~~rate~~Default ofthat ~~Libor~~arose ~~plus~~or 10would otherwise arise under the Financing Agreement for failing to comply with the Fixed Charge Coverage Ratio for the six months ended March 31, 2019.00 The Third Amendment increased the original exit fee of 3.0% ~~(12~~to 6.530%. The original exit fee of 3% was included in the Financing Agreement at ~~December~~the 31execution date and the increase of the total exit fee to 6% was included as part of the amendment dated February 13, ~~2018~~2019 discussed above and this Third Amendment. The exit fee is applied to the principal amount of the loans made under the Financing Agreement that is payable on the earliest of (a) the final maturity date, (b) the termination date of the Financing agreement for any reason, (c) the acceleration of the obligations in the Financing Agreement for any reason and (d) the date of any refinancing of the term loan under the Financing Agreement.

On August 16, 2019, we entered into the Fourth Amendment to the Financing Agreement originally executed on December 27, 2017 with the Lenders. The Fourth Amendment provides a $5.0 million term loan provided by the Lenders to us under the delayed draw feature of the Financing Agreement, and extended the period by which an applicable premium payable to the Lenders will be calculated to the final maturity date.

On September 6, 2019, we entered into the Fifth Amendment to the Financing Agreement. The Fifth Amendment (i) extended the maturity of the Financing Agreement to December 27, 2022, (ii) provided us with a $5.0 million term loan provided by the Lenders under the delayed draw feature of the Financing Agreement, (iii) extended the period by which an applicable premium payable to the Lenders will be calculated to December 31, 2021, (iv) modified certain definitions and concepts to account for our recent acquisition of properties from Blackjewel, (v) permitted the disposition of the Pennyrile mining complex and (vi) provided for the payment of additional fees to the Lenders, including a consent fee of $1.0 million, an amendment fee of $825,000 and an increase in the lender exit fee of 1.00% to a total exit fee of 7.0% of the amount of term loans made under the Financing Agreement that is payable upon the maturity of the Financing Agreement.

At December 31, 2019, $27.5 million was outstanding under the financing agreement at a variable interest rate of Libor plus 10.00% (11.80% at December 31, 2019), $5.0 million of borrowings outstanding at a variable interest rate of Libor plus 10.00% (11.74% at December 31, 2019) and $5.0 million of borrowings outstanding at a variable interest rate of Libor plus 10.00% (11.71% at December 31, 2019).

Common Unit Warrants

WeOn December 27, 2017, we entered into a warrant agreement with certain parties that are also parties to the Financing Agreement discussed above. The warrant agreement included the issuance of a total of 683,888 Common Unit Warrants at an exercise price of $1.95 per unit, which was the closing price of our units on the OTC market as of December 27, 2017. The Common Unit Warrants have a five year expiration date. The Common Unit Warrants and the Rhino common units after exercise are both transferable, subject to applicable US securities laws. The Common Unit Warrant exercise price is $1.95 per unit, but the price per unit will be reduced by future common unit distributions and other further adjustments in price included in the warrant agreement for transactions that are dilutive to the amount of Rhino’s common units outstanding. The warrant agreement includes a provision for a cashless exercise where the warrant holders can receive a net number of common units. Per the warrant agreement, the warrants are detached from the Financing Agreement and fully transferable.

Letter of Credit Facility – PNC Bank

On December 27, 2017, we entered the LoC Facility Agreement with PNC, pursuant to which PNC agreed to provide us with the LoC Facility. The LoC Facility Agreement provided that we pay a quarterly fee at a rate equal to 5% per annum calculated based on the daily average of letters of credit outstanding under the LoC Facility, as well as administrative costs incurred by PNC and a $100,000 closing fee. The LoC Facility Agreement provided that we reimburse PNC for any drawing under a letter of credit by a specified beneficiary as soon as possible after payment was made. Our obligations under the LoC Facility Agreement were secured by a first lien security interest on a cash collateral account that was required to contain no less than 105% of the face value of the outstanding letters of credit. In the event the amount in such cash collateral account was insufficient to satisfy our reimbursement obligations, the amount outstanding would bear interest at a rate per annum equal to the Base Rate (as that term was defined in the LoC Facility Agreement) plus 2.0%. We would indemnify PNC for any losses which PNC may have incurred as a result of the issuance of a letter of credit or PNC’s failure to honor any drawing under a letter of credit, subject in each case to certain exceptions. We provided cash collateral to our counterparties during the third quarter of 2018 and as of September 30, 2018, the LoC Facility was terminated. We had no outstanding letters of credit as of December 30, 2018.

Off-Balance Sheet Arrangements

In the normal course of business, we are a party to off-balance sheet arrangements that include guarantees and financial instruments with off-balance sheet risk, such as bank letters of credit and surety bonds. No liabilities related to these arrangements are reflected in our consolidated balance sheet, and we do not expect any material adverse effects on our financial condition, results of operations or cash flows to result from these off-balance sheet arrangements.

Federal and state laws require us to secure certain long-term obligations related to mine closure and reclamation costs. We typically secure these obligations by using surety bonds, an off-balance sheet instrument. The use of surety bonds is less expensive for us than the alternative of posting a 100% cash bond or a bank letter of credit. We then provide cash collateral to secure our surety bonding obligations in an amount up to a certain percentage of the aggregate bond liability that we negotiate with the surety companies. To the extent that surety bonds become unavailable, we would seek to secure our reclamation obligations with letters of credit, cash deposits or other suitable forms of collateral.

As of December 31, ~~2018~~ 2019, we had $87.29 million in cash collateral held by third-parties of which $3.0 million serves as collateral ~~for~~ for approximately $4241.6 million in surety bonds outstanding that secure the performance of our reclamation obligations. The other $54.29 million serves as collateral for our self-insured workers’ compensation program. Of the $4241.6 million~~, approximately~~ ~~$0.4~~of ~~million relates to~~ surety bonds ~~for Deane Mining~~, ~~LLC and~~ approximately $30.4 million relates to surety bonds for ~~Sands~~Deane ~~Hill~~ Mining, LLC, which ~~in each case~~ have not been transferred or replaced by the ~~buyers of~~buyer of Deane Mining, LLC ~~or Sands Hill Mining, LLC~~ as was agreed to by the parties as part of the ~~transactions~~transaction. We can provide no assurances that a surety company will underwrite the surety bonds of the ~~purchasers~~purchaser of ~~these~~Deane ~~entities~~Mining LLC, nor are we aware of the actual amount of reclamation at any given time. Further, if there was a claim under these surety bonds prior to the transfer or replacement of such bonds by the buyer ~~buyers~~ of Deane Mining, LLC ~~or Sands Hill Mining~~, ~~LLC, then~~ we may be responsible to the surety company for any amounts it pays in respect of such claim. ~~While~~ While the ~~buyers~~buyer ~~are~~is required to indemnify us for damages, including reclamation liabilities, pursuant to the agreements governing the sales of ~~these~~this ~~entities~~entity, we may not be successful in obtaining any indemnity or any amounts received may be inadequate. See Part I I “Business—Regulation and Laws—Surety Bonds.”

Critical Accounting Policies and Estimates

Our financial statements are prepared in accordance with accounting principles that are generally accepted in the United States. The preparation of these financial statements requires management to make estimates and judgments that affect the reported amount of assets, liabilities, revenues and expenses as well as the disclosure of contingent assets and liabilities. Management evaluates its estimates and judgments on an on-going basis. Management bases its estimates and judgments on historical experience and other factors that are believed to be reasonable under the circumstances. Nevertheless, actual results may differ from the estimates used and judgments made. Note 2 to the consolidated financial statements included elsewhere in this annual report provides a summary of all significant accounting policies. We believe that of these significant accounting policies, the following may involve a higher degree of judgment or complexity.

7780

Property, Plant and Equipment

Property, plant, and equipment, including coal properties, mine development costs and construction costs, are recorded at cost, which includes construction overhead and interest, where applicable. Expenditures for major renewals and betterments are capitalized, while expenditures for maintenance and repairs are expensed as incurred. Mining and other equipment and related facilities are depreciated using the straight-line method based upon the shorter of estimated useful lives of the assets or the estimated life of each mine. Coal properties are depleted using the units-of-production method, based on estimated proven and probable reserves. Mine development costs are amortized using the units-of-production method, based on estimated proven and probable reserves. Gains or losses arising from sales or retirements are included in current operations.

On March 30, 2005, the Financial Accounting Standards Board (FASB) ratified the consensus reached by the Emerging Issues Task Force, or EITF, on accounting for stripping costs in the mining industry. This accounting guidance applies to stripping costs incurred in the production phase of a mine for the removal of overburden or waste materials for the purpose of obtaining access to coal that will be extracted. Under the guidance, stripping costs incurred during the production phase of the mine are variable production costs t

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