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. Our investments have included joint ventures that provide for the
transportation of hydrocarbons and drilling support services in the Utica Shale region. We have also invested in joint ventures
that provide sand for fracking operations to drillers in the Utica Shale region and other oil and natural gas basins in the United
States.
We
have a geographically diverse asset base with coal reserves located in Central Appalachia, Northern Appalachia, the Illinois Basin
and the Western Bituminous region. As of December 31, 2017, we controlled an estimated 252.7 million tons of proven and probable
coal reserves, consisting of an estimated 200.1 million tons of steam coal and an estimated 52.6 million tons of metallurgical
coal. In addition, as of December 31, 2017, we controlled an estimated 185.2 million tons of non-reserve coal deposits. Our estimated
non-reserve coal deposits as of December 31, 2017 decreased when compared to the estimated non-reserve coal deposits reported
as of December 31, 2016 due to the sale of our Sands Hill Mining operation in November 2017. Periodically, we retain outside experts
to independently verify our coal reserve and our non-reserve coal deposit estimates. The most recent audit by an independent engineering
firm of our coal reserve and non-reserve coal deposit estimates was completed by Marshall Miller & Associates, Inc. as of
November 30, 2016, and covered a majority of the coal reserves and non-reserve coal deposits that we controlled as of such date.
The coal reserve estimates were updated through December 31, 2017 by our internal staff of engineers based upon production data.
We intend to continue to periodically retain outside experts to assist management with the verification of our estimates of our
coal reserves and non-reserve coal deposits going forward.
We
operate underground and surface mines located in Kentucky, Ohio, West Virginia and Utah. The number of mines that we operate will
vary from time to time depending on a number of factors, including the existing demand for and price of coal, depletion of economically
recoverable reserves and availability of experienced labor.
For
the year ended December 31, 2017, we produced approximately 4.2 million tons of coal from continuing operations and sold approximately
4.1 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, 2017, our available liquidity was $8.8 million. We also have a delayed draw term loan commitment in the amount
of $40 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 Agreement (“Financing Agreement”), which provides us with a multi-draw
loan in the 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 an additional $40 million commitment that
is contingent upon the satisfaction of certain conditions precedent specified in the Financing Agreement. We used approximately
$17.3 million of the net proceeds thereof to repay all amounts outstanding and terminate the Amended and Restated Credit Agreement
with PNC Bank, National Association, as Administrative Agent. The Financing Agreement terminates on December 27, 2020. For more
information about our new Financing Agreement, please read “— Recent Developments—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 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 have 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 $40 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.
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”).
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 due on December 27, 2020. 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 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; (ii) the requirement
to notify the Administrative Agent of certain events, including events of default under the Financing Agreement, dispositions,
entry into material contracts, (iii) the requirement to maintain insurance, obtain permits, and comply with environmental and
reclamation laws (iv) 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 (v) 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) make capital expenditures in excess, or, with respect to maintenance capital expenditures,
lower than, specified amounts, (iv) incur restrictions on the payment of dividends, (v) prepay or modify the terms of other indebtedness,
(vi) permit the Collateral Coverage Amount to be less than the outstanding principal amount of the loans outstanding under the
Financing Agreement or (vii) 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,
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.
Common
Unit Warrants
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 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 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 has 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 provides that we will 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 provides that we will reimburse PNC for any drawing under a letter of credit by a specified
beneficiary as soon as possible after payment is made. Our obligations under the LoC Facility Agreement will be secured by a first
lien security interest on a cash collateral account that is 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 is insufficient to satisfy our reimbursement obligations,
the amount outstanding will bear interest at a rate per annum equal to the Base Rate (as that term is defined in the LoC Facility
Agreement) plus 2.0%. We will indemnify PNC for any losses which PNC may incur 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. The LoC Facility
Agreement expires on December 31, 2018. We had $11.2 million of letters of credit at December 31, 2017 under the LoC Facility
with cash collateral in the amount of $12.3 million. We anticipate providing collateral with our counterparties prior to the expiration
of the LoC Facility on December 31, 2018.
Sands
Hill Mining LLC Disposition
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 our Sands Hill Mining entity to the third party in exchange for a future override royalty for any mineral sold,
excluding coal, from Sands Hill Mining LLC after the closing date. We recognized a 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. The previous operating
results of Sands Hill Mining LLC have been reclassified and reported on the (Gain)/loss from discontinued operations line on our
consolidated statements of operations and comprehensive income for the years ended December 31, 2017 and 2016. The current and
non-current assets and liabilities previously related to Sands Hill Mining LLC have been reclassified to the appropriate held
for sale categories on our consolidated statement of financial position at December 31, 2016.
Acquisition
by Royal Energy Resources, Inc.
On
January 21, 2016, a definitive agreement (“Definitive Agreement”) was completed between Royal Energy Resources, Inc.
(“Royal”) and Wexford Capital LP (“Wexford Capital”) whereby Royal acquired 676,912 of our common units
from Wexford Capital for $3.5 million. The Definitive Agreement also included the committed acquisition by Royal within sixty
days from the date of the Definitive Agreement of all of the issued and outstanding membership interests of Rhino GP LLC, our
general partner, as well as 945,525 of subordinated units from Wexford Capital for $1.0 million.
On
March 17, 2016, Royal completed the acquisition of all of the membership interests of our general partner as well as the 945,525
subordinated units from Wexford Capital. Royal obtained control of, and a majority limited partner interest, in us with the completion
of this transaction.
On
March 21, 2016, we entered into a securities purchase agreement (the “Securities Purchase Agreement”) with Royal pursuant
to which we issued 6,000,000 of our common units to Royal in a private placement at $1.50 per common unit for an aggregate purchase
price of $9.0 million. Royal paid us $2.0 million in cash and delivered a promissory note payable to us (“Rhino Promissory
Note”) in the amount of $7.0 million. On May 13, 2016 and September 30, 2016, Royal paid us $3.0 million and $2.0 million,
respectively, for the promissory note installments. The payments were made in relation to the fifth amendment of our former amended
and restated credit agreement completed on May 13, 2016. On December 30, 2016, we modified the Securities Purchase Agreement with
Royal for the final $2.0 million payment due on or before December 31, 2016 to extend the due date to December 31, 2018. Please
read “—Letter Agreement Regarding Rhino Promissory Note and Weston Promissory Note.”
Pursuant
to the Securities Purchase Agreement, on March 21, 2016, we and Royal entered into a registration rights agreement. The registration
rights agreement grants Royal piggyback registration rights under certain circumstances with respect to the common units issued
to Royal pursuant to the Securities Purchase Agreement.
Option
Agreement-Armstrong Energy
On
December 30, 2016, we entered into an option agreement (the “Option Agreement”) with Royal, Rhino Resources Partners
Holdings, LLC (“Rhino Holdings”), an entity wholly owned by certain investment partnerships managed by Yorktown Partners
LLC (“Yorktown”), and our general partner. Upon execution of the Option Agreement, we received an option (the “Call
Option”) from Rhino Holdings to acquire substantially all of the outstanding common stock of Armstrong Energy, Inc. (“Armstrong
Energy”) that is owned by investment partnerships managed by Yorktown, representing approximately 97% of the outstanding
common stock of Armstrong Energy. Armstrong Energy, Inc. is a coal producing company with approximately 445 million tons of proven
and probable reserves and five mines located in the Illinois Basin in western Kentucky as of June 30, 2017. The Option Agreement
stipulates that we can exercise the Call Option no earlier than January 1, 2018 and no later than December 31, 2019. In exchange
for Rhino Holdings granting us the Call Option, we issued 5.0 million common units, representing limited partner interests in
us (the “Call Option Premium Units”) to Rhino Holdings upon the execution of the Option Agreement. The Option Agreement
stipulates we can exercise the Call Option and purchase the common stock of Armstrong Energy in exchange for a number of common
units to be issued to Rhino Holdings, which when added with the Call Option Premium Units, will result in Rhino Holdings owning
51% of the fully diluted common units of us. The purchase of Armstrong Energy through the exercise of the Call Option would also
require Royal to transfer a 51% ownership interest in our general partner to Rhino Holdings. Our ability to exercise the Call
Option is conditioned upon (i) sixty (60) days having passed since the entry by Armstrong Energy into an agreement with its bondholders
to restructure its bonds and (ii) the amendment of our former revolving credit facility to permit the acquisition of Armstrong
Energy (refer to our Financing Agreement discussed previously).
The
Option Agreement also contains an option (the “Put Option”) granted by us to Rhino Holdings whereby Rhino Holdings
has the right, but not the obligation, to cause us to purchase substantially all of the outstanding common stock of Armstrong
Energy from Rhino Holdings under the same terms and conditions discussed above for the Call Option. The exercise of the Put Option
is dependent upon (i) the entry by Armstrong Energy into an agreement with its bondholders to restructure its bonds and (ii) the
termination and repayment of any outstanding balance under our former revolving credit facility which occurred on December 27,
2017 (refer to our Financing Agreement discussed previously).
The
Option Agreement contains customary covenants, representations and warranties and indemnification obligations for losses arising
from the inaccuracy of representations or warranties or breaches of covenants contained in the Option Agreement, the seventh amendment
of our former credit facility and the GP Amendment (defined below). Upon the request by Rhino Holdings, we will also enter into
a registration rights agreement that provides Rhino Holdings with the right to demand two shelf registration statements and registration
statements on Form S-1, as well as piggyback registration rights for as long as Rhino Holdings owns at least 10% of the outstanding
common units.
Pursuant
to the Option Agreement, the Second Amended and Restated Limited Liability Company Agreement of our general partner was amended
(“GP Amendment”). Pursuant to the GP Amendment, Mr. Bryan H. Lawrence was appointed to the board of directors of our
general partner as a designee of Rhino Holdings and Rhino Holdings has the right to appoint an additional independent director.
Rhino Holdings has the right to appoint two members to the board of our general partner for as long as it continues to own 20%
of the common units on an undiluted basis. The GP Amendment also provided Rhino Holdings with the authority to consent to any
delegation of authority to any committee of the board of our general partner. Upon the exercise of the Call Option or the Put
Option, the Second Amended and Restated Limited Liability Company Agreement of our general partner, as amended, will be further
amended to provide that Royal and Rhino Holdings will each have the ability to appoint three directors and that the remaining
director will be the chief executive officer of our general partner unless agreed otherwise.
The
Option Agreement superseded and terminated the equity exchange agreement entered into on September 30, 2016 by and among Royal,
Rhino Holdings and our general partner.
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 the
Option Agreement was deemed to have no carrying value. An impairment charge of $21.8 million related to the Option Agreement has
been recorded on the Asset impairment and related charges line of the consolidated statements of operations and comprehensive
income. Please read “Part II, Item 7, Management’s Discussion and Analysis of Financial condition and Results of Operations—Asset
Impairments 2017.”
Series
A Preferred Unit Purchase Agreement
On
December 30, 2016, we entered into a Series A Preferred Unit Purchase Agreement (the “Preferred Unit Agreement”) with
Weston Energy LLC (“Weston”), an entity wholly owned by certain investment partnerships managed by Yorktown, and Royal.
Under the Preferred Unit Agreement, Weston and Royal agreed to purchase 1,300,000 and 200,000, respectively, of Series A preferred
units representing limited partner interests in us at a price of $10.00 per Series A preferred unit. The Series A preferred units
have the preferences, rights and obligations set forth in our Fourth Amended and Restated Agreement of Limited Partnership, which
is described below. In exchange for the Series A preferred units, Weston and Royal paid cash of $11.0 million and $2.0 million,
respectively, to us and Weston assigned to us a $2.0 million note receivable from Royal originally dated September 30, 2016 (the
“Weston Promissory Note”). Please read “—Letter Agreement Regarding Rhino Promissory Note and Weston Promissory
Note.”
The
Preferred Unit Agreement contains customary representations, warrants and covenants, which include among other things, that, for
as long as the Series A preferred units are outstanding, we will cause CAM Mining, LLC, one of our subsidiaries, (“CAM Mining”)
to conduct its business in the ordinary course consistent with past practice and use reasonable best efforts to maintain and preserve
intact its current organization, business and franchise and to preserve the rights, franchises, goodwill and relationships of
its employees, customers, lenders, suppliers, regulators and others having business relationships with CAM Mining.
The
Preferred Unit Agreement stipulates that upon the request of the holder of the majority of our common units following their conversion
from Series A preferred units, as outlined in our partnership agreement, we will enter into a registration rights agreement with
such holder. Such majority holder has the right to demand two shelf registration statements and registration statements on Form
S-1, as well as piggyback registration rights.
Letter
Agreement Regarding Rhino Promissory Note and Weston Promissory Note
On
December 30, 2016, we entered into a letter agreement with Royal whereby the maturity dates of the Weston Promissory Note and
the final installment payment of the Rhino Promissory Note were extended to December 31, 2018. The letter agreement further provided
that the aggregate $4.0 million balance of the Weston Promissory Note and Rhino Promissory Note may be converted at Royal’s
option into a number of shares of Royal’s common stock equal to the outstanding balance multiplied by seventy-five percent
(75%) of the volume-weighted average closing price of Royal’s common stock for the 90 days preceding the date of conversion
(“Royal VWAP”), subject to a minimum Royal VWAP of $3.50 and a maximum Royal VWAP of $7.50. On September 1, 2017,
Royal elected to convert the Rhino Promissory Note and the Weston Promissory Note to shares of Royal common stock. Royal issued
914,797 shares of its common stock to us at a conversion price of $4.51 as calculated per the method stipulated above. We recorded
the $4.1 million conversion of the Weston Promissory Note and Rhino Promissory Note as Investment in Royal common stock in the
Partners’ Capital section of our consolidated statements of financial position. (See Note 13 of the consolidated financial
statements included elsewhere in this annual report for further information on the conversion of the Weston Promissory Note and
the Rhino Promissory Note to Royal common stock.)
Fourth
Amended and Restated Agreement of Limited Partnership of Rhino Resource Partners LP
On
December 30, 2016, our general partner entered into the Fourth Amended and Restated Agreement of Limited Partnership of the Partnership
(“Amended and Restated Partnership Agreement”) to create, authorize and issue the Series A preferred units.
The
Series A preferred units are a new class of equity security that rank senior to all classes or series of our equity securities
with respect to distribution rights and rights upon liquidation. The holders of the Series A preferred units 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 our common units. The Series A preferred units will be liquidated in accordance with their capital
accounts and upon liquidation will be entitled to distributions of property and cash in accordance with the balances of their
capital accounts prior to such distributions to equity securities that rank junior to the Series A preferred units.
The
Series A preferred units vote on an as-converted basis with the common units, and we will be restricted from taking certain actions
without the consent of the holders of a majority of the Series A preferred units, including: (i) the issuance of additional Series
A preferred units, or securities that rank senior or equal to the Series A preferred units; (ii) the sale or transfer of CAM Mining
or a material portion of its assets; (iii) the repurchase of common units, or the issuance of rights or warrants to holders of
common units entitling them to purchase common units at less than fair market value; (iv) consummation of a spin off; (v) the
incurrence, assumption or guaranty indebtedness for borrowed money in excess of $50.0 million except indebtedness relating to
entities or assets that are acquired by us or our affiliates that is in existence at the time of such acquisition or (vi) the
modification of CAM Mining’s accounting principles or the financial or operational reporting principles of our Central Appalachia
business segment, subject to certain exceptions.
We
have the option to convert the outstanding Series A preferred 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. Each Series A preferred unit will convert
into a number of common units equal to the quotient (the “Series A Conversion Ratio”) of (i) the sum of $10.00 and
any unpaid distributions in respect of such Series A Preferred Unit divided by (ii) 75% of the volume-weighted average closing
price of the common units for the preceding 90 trading days (the “VWAP”); provided however, that the VWAP will be
capped at a minimum of $2.00 and a maximum of $10.00. On December 31, 2021, all outstanding Series A preferred units will convert
into common units at the then applicable Series A Conversion Ratio.
Elk
Horn Coal Leasing Disposition
In
August 2016, we entered into an agreement to sell our Elk Horn coal leasing company (“Elk Horn”) to a third party
for total cash consideration of $12.0 million. We received $10.5 million in cash consideration upon the closing of the Elk Horn
transaction and the remaining $1.5 million of consideration was paid in ten equal monthly installments of $150,000 on the 20th
of each calendar month beginning on September 20, 2016. We recorded net loss of $119.9 million from the Elk Horn disposal during
the year ended December 31, 2016. The previous operating results of Elk Horn have been reclassified and reported on the (Gain)/loss
from discontinued operations line on our consolidated statements of operations and comprehensive income for the year ended December
31, 2016.
Delisting
of Common Units from NYSE
On
December 17, 2015, the New York Stock Exchange (“NYSE”) notified us that the NYSE had determined to commence proceedings
to delist our common units from the NYSE as a result of our failure to comply with the continued listing standard set forth in
Section 802.01B of the NYSE Listed Company Manual to maintain an average global market capitalization over a consecutive 30 trading-day
period of at least $15 million for our common units. The NYSE also suspended the trading of our common units at the close of trading
on December 17, 2015.
On
January 4, 2016, we filed an appeal with the NYSE to review the suspension and delisting determination of our common units. The
NYSE held a hearing regarding our appeal on April 20, 2016 and affirmed its prior decision to delist our common units.
On
April 27, 2016, the NYSE filed with the SEC a notification of removal from listing and registration on Form 25 to delist our common
units and terminate the registration of our common units under Section 12(b) of the Securities Exchange Act of 1934. The delisting
became effective on May 9, 2016. Our common units trade on the OTCQB Marketplace under the ticker symbol “RHNO.”
We
are exploring the possibility of listing our common units on the NASDAQ Stock Market (“NASDAQ”), pending our capability
to meet the NASDAQ initial listing standards.
Reverse
Unit Split
On
April 18, 2016, we completed a 1-for-10 reverse split on our common units and subordinated units. Pursuant to the reverse split,
common unitholders received one common unit for every 10 common units owned on April 18, 2016 and subordinated unitholders received
one subordinated unit for every 10 subordinated units owned on April 18, 2016. All common and subordinated units, net income (loss)
per unit and distribution per unit references included herein have been adjusted as if the change took place before the date of
the earliest transaction reported. Any fractional units resulting from the reverse unit split were rounded to the nearest whole
unit.
Distribution
Suspension
Beginning
with the quarter ended June 30, 2015 and continuing through the quarter ended December 31, 2017, 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 quarters ended June 30, 2015 through
December 31, 2017, we have accumulated arrearages at December 31, 2017 related to the common unit distribution of approximately
$439.3 million.
History
Our
predecessor was formed in April 2003 by Wexford Capital. We were formed in April 2010 to own and control the coal properties and
related assets owned by Rhino Energy LLC. On October 5, 2010, we completed our IPO. Our common units were originally listed on
the New York Stock Exchange under the symbol “RNO”. Please read “—Recent Developments—Delisting
of Common Units from NYSE.” In connection with the IPO, Wexford contributed their membership interests in Rhino Energy LLC
to us, and in exchange we issued subordinated units representing limited partner interests in us and common units to Wexford and
issued incentive distribution rights to our general partner. In March 2016, Royal acquired our general partner and a majority
limited partner interest in us from Wexford. Please read “—Recent Developments— Royal Energy Resources, Inc.
Acquisition.”
Since
the formation of our predecessor in April 2003, we have completed numerous coal asset acquisitions with a total purchase price
of approximately $357.5 million. Through these acquisitions and coal lease transactions, we have substantially increased our proven
and probable coal reserves and non-reserve coal deposits. In addition, we have successfully grown our production through internal
development projects.
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, 2017, we operated two mining complexes located in Central Appalachia (Tug River and Rob Fork). In August 2016,
we completed the sale of our Elk Horn coal leasing operation. In addition during 2017, we operated two mining complexes located
in Northern Appalachia (Hopedale and Sands Hill). Our Sands Hill Mining operation was sold in November 2017. In the Western Bituminous
region, we operated one mining complex located in Emery and Carbon Counties, Utah (Castle Valley). We also operated a mining complex
in the Illinois Basin, our Riveredge mine at our Pennyrile mining complex. (See Note 4 of the consolidated financial statements
included elsewhere in this annual report for further information on the disposition of Sands Hill Mining and Elk Horn Coal Company)
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 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.
The
following map shows the location of our coal mining and leasing operations as of December 31, 2017 (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, 2017.
Region
|
|
Preparation
Plants and
Loadouts
|
|
Transportation
to Customers(1)
|
|
Number
and
Type
of Active Mines(2)
|
|
|
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)
|
|
|
2S
|
|
|
|
0.9
|
|
Rob
Fork Complex (KY)
|
|
Rob
Fork
|
|
Truck,
Barge, Rail (CSX)
|
|
|
1U,1S
|
|
|
|
0.6
|
|
Northern
Appalachia(5)
|
|
|
|
|
|
|
|
|
|
|
|
|
Hopedale
Complex (OH)
|
|
Nelms
|
|
Truck,
Rail (OHC, WLE)
|
|
|
1U
|
|
|
|
0.4
|
|
Illinois
Basin
|
|
|
|
|
|
|
|
|
|
|
|
|
Taylorville
Field (IL)
|
|
n/a
|
|
Rail
(NS)
|
|
|
—
|
|
|
|
—
|
|
Pennyrile
Complex (KY)
|
|
Preparation
plant & river loadout
|
|
Barge
|
|
|
1U
|
|
|
|
1.3
|
|
Western
Bituminous
|
|
|
|
|
|
|
|
|
|
|
|
|
Castle
Valley Complex (UT)
|
|
Truck
loadout
|
|
Truck
|
|
|
1U
|
|
|
|
1.0
|
|
McClane
Canyon Mine (CO)(6)
|
|
n/a
|
|
Truck
|
|
|
—
|
|
|
|
—
|
|
Total
|
|
|
|
|
|
|
4U,3S
|
|
|
|
4.2
|
|
(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, 2017 were company-operated.
|
|
|
(3)
|
Total
production based on actual amounts and not rounded amounts shown in this table.
|
|
|
(4)
|
Jamboree
includes only a loadout facility.
|
|
|
(5)
|
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.
|
Central
Appalachia.
For the year ended December 31, 2017, we operated two mining complexes located in Central Appalachia consisting
of one active underground mine and three surface mines. For the year ended December 31, 2017, the mines at our Tug River and Rob
Fork mining complexes produced an aggregate of approximately 0.9 million tons of steam coal and an estimated 0.6 million tons
of metallurgical coal.
Tug
River Mining Complex.
Our Tug River mining complex is located in Kentucky and West Virginia bordering the Tug River. This
complex produces coal from two company-operated surface mines, which includes one high-wall mining unit. Coal production from
these operations is delivered to the Tug Fork preparation plant for processing and then transported by truck to the Jamboree rail
loadout for blending and shipping. Coal suitable for direct-ship to customers is delivered by truck directly to the Jamboree rail
loadout from the mine sites. The Tug Fork plant is a modern, 350 tons per hour preparation plant utilizing heavy media circuitry
that is capable of cleaning coarse and fine coal size fractions. The Jamboree loadout is located on the Norfolk Southern Railroad
and is a modern unit train, batch weigh loadout. This mining complex produced approximately 0.7 million tons of steam coal and
approximately 0.2 million tons of metallurgical coal for the year ended December 31, 2017.
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 0.2 million tons of steam coal and 0.4 million tons of metallurgical coal for the year ended December 31, 2017.
Northern
Appalachia.
For the majority of the year ended December 31, 2017, we operated two mining complexes located in Northern
Appalachia consisting of one company-operated underground mine and one company-operated surface mine. For the year ended December
31, 2017, these mines produced an aggregate of approximately 0.4 million tons of steam coal. We sold our Sands Hill Mining operation
in November 2017, which consisted of one company-operated surface mine.
Hopedale
Mining Complex.
The Hopedale mining complex includes an underground mine located in Hopedale, Ohio approximately five miles
northeast of Cadiz, Ohio. Coal produced from the Hopedale mine is first cleaned at our Nelms preparation plant located on the
Ohio Central Railroad and the Wheeling & Lake Erie Railroad and then shipped by train or truck to our customers. The infrastructure
includes a full-service loadout facility. This underground mining operation produced approximately 0.4 million tons of steam coal
for the year ended December 31, 2017.
Sands
Hill Mining Complex.
We operated one surface mine at our Sands Hill mining complex, located near Hamden, Ohio, which was sold
in November 2017. The Sands Hill mining complex produced approximately 60,000 tons of steam coal and approximately 0.3 million
tons of limestone aggregate for the year ended December 31, 2017.
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, 2017.
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 and 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 fully permitted and provides us with access to Illinois Basin coal that 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, 2017. 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.
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 Energy Services, Inc. (NASDAQ: TUSK) (“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/(loss) for this investment for the years ended December 31, 2017 and 2016 of approximately
$36,000 and ($0.2) million, respectively. 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, 2017, we owned 568,794 shares of Mammoth Inc.
As
of December 31, 2017 and 2016, we recorded a fair market value adjustment of $2.6 million and $1.6 million, respectively, for
our available-for-sale investment in Mammoth Inc. based on the market value of the shares at December 31, 2017 and 2016, respectively,
which was recorded in Other Comprehensive Income. As of December 31, 2017 and 2016, we have recorded our investment in Mammoth
Inc. as a short-term asset, which we have classified as available-for-sale. We have included our investment in Mammoth Inc. and
our prior investment in Muskie and Sturgeon in our Other category for segment reporting purposes.
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, 2017, approximately
82.0% of our coal sales tons consisted of steam coal and approximately 18.0% consisted of metallurgical coal. For the year ended
December 31, 2017, approximately 57.0% 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, 2017, we derived approximately 86.9% of our total coal revenues from sales to
our ten largest customers, with affiliates of our top three customers accounting for approximately 39.4% of our coal revenues
for that period: LG&E (18.3%); Integrity Coal (11.0%); and Dominion Energy (10.1%).
Coal
Supply Contracts
For
the years ended December 31, 2017 and 2016, approximately 59% and 90%, 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, 2017, we had commitments under supply contracts to deliver annually scheduled base quantities as follows:
Year
|
|
Tons
(in thousands)
|
|
|
Number
of customers
|
2018
|
|
|
3,585
|
|
|
15
|
2019
|
|
|
850
|
|
|
3
|
2020
|
|
|
850
|
|
|
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 Natural
Resources, Inc., Arch Coal, Inc., Booth Energy Group, Blackhawk Mining, LLC, Murray Energy Corporation, Foresight Energy LP, Westmoreland
Resource Partners, LP and Bowie Resource Partners LLC.
The
most important factors on which we compete are coal price, coal quality and characteristics, transportation costs and the reliability
of supply. Demand for coal and the prices that we will be able to obtain for our coal are closely linked to coal consumption patterns
of the domestic electric generation industry and international consumers. These coal consumption patterns are influenced by factors
beyond our control, including demand for electricity, which is significantly dependent upon economic activity and summer and winter
temperatures in the United States, government regulation, technological developments and the location, availability, quality and
price of competing sources of fuel such as natural gas, oil and nuclear, and alternative energy sources such as hydroelectric
power and wind power.
Regulation
and Laws
Our
operations are subject to regulation by federal, state and local authorities on matters such as:
|
●
|
employee
health and safety;
|
|
|
|
|
●
|
governmental
approvals and other authorizations such as mine permits, as well as other licensing requirements;
|
|
|
|
|
●
|
air
quality standards;
|
|
|
|
|
●
|
water
quality standards;
|
|
|
|
|
●
|
storage,
treatment, use and disposal of petroleum products and other hazardous substances;
|
|
|
|
|
●
|
plant
and wildlife protection;
|
|
|
|
|
●
|
reclamation
and restoration of mining properties after mining is completed;
|
|
|
|
|
●
|
the
discharge of materials into the environment, including waterways or wetlands;
|
|
|
|
|
●
|
storage
and handling of explosives;
|
|
|
|
|
●
|
wetlands
protection;
|
|
|
|
|
●
|
surface
subsidence from underground mining;
|
|
|
|
|
●
|
the
effects, if any, that mining has on groundwater quality and availability; and
|
|
|
|
|
●
|
legislatively
mandated benefits for current and retired coal miners.
|
In
addition, many of our customers are subject to extensive regulation regarding the environmental impacts associated with the combustion
or other use of coal, which could affect demand for our coal. The possibility exists that new laws or regulations, or new interpretations
of existing laws or regulations, may be adopted that may have a significant impact on our mining operations 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, 2017 our average MSHA violations per inspection day was 0.29 as compared to the most recent national
average of 0.67 violations per inspection day for coal mining activity as reported by MSHA, or 56.72% 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 recently released Pattern of Violation (“POV”) regulations under the Mine Act. Under
this regulation, MSHA eliminated the ninety (90) day window to take corrective action and engage in mitigation efforts for mine
operators who met certain initial POV screening criteria. Additionally, MSHA will make POV determinations based upon enforcement
actions as issued, rather than enforcement actions that have been rendered final following the opportunity for administrative
or judicial review. After a mine operator has been placed on POV status, MSHA will thereafter issue an order withdrawing miners
from the area affected by any enforcement action designated by MSHA as posing a significant and substantial, or S&S, hazard
to the health and/or safety of miners. Further, once designated as a POV mine, a mine operator can be removed from POV status
only upon: (1) a complete inspection of the entire mine with no S&S enforcement actions issued by MSHA; or (2) no POV-related
withdrawal orders being issued by MSHA within ninety (90) days of the mine operator being placed on POV status. Although it remains
to be seen how these new regulations will ultimately affect production at our mines, they are consistent with the trend of more
stringent enforcement.
From
time to time, certain portions of individual mines have been required to suspend or shut down operations temporarily in order
to address a compliance requirement or because of an accident. For instance, MSHA issues orders pursuant to Section 103(k) that,
among other things, call for operations in the area of the mine at issue to suspend operations until compliance is restored. Likewise,
if an accident occurs within a mine, the MSHA requirements call for all operations in that area to be suspended until the circumstance
leading to the accident has been resolved. During the fiscal year ended December 31, 2017 (as in earlier years), we received such
orders from government agencies and have experienced accidents within our mines requiring the suspension or shutdown of operations
in those particular areas until the circumstances leading to the accident have been resolved. While the violations or other circumstances
that caused such an accident were being addressed, other areas of the mine could and did remain operational. These circumstances
did not require us to suspend operations on a mine-wide level or otherwise entail material financial or operational consequences
for us. Any suspension of operations at any one of our locations that may occur in the future may have material financial or operational
consequences for us.
It
is our practice to contest notices of violations in cases in which we believe we have a good faith defense to the alleged violation
or the proposed penalty and/or other legitimate grounds to challenge the alleged violation or the proposed penalty. We exercise
substantial efforts toward achieving compliance at our mines. For example, we have further increased our focus with regard to
health and safety at all of our mines. These efforts include hiring additional skilled personnel, providing training programs,
hosting quarterly safety meetings with MSHA personnel and making capital expenditures in consultation with MSHA aimed at increasing
mine safety. We believe that these efforts have contributed, and continue to contribute, positively to safety and compliance at
our mines. In “Part 1, Item 4. Mine Safety Disclosure” and in Exhibit 95.1 to this Annual Report on Form 10-K, we
provide additional details on how we monitor safety performance and MSHA compliance, as well as provide the mine safety disclosures
required pursuant to Section 1503(a) of the Dodd-Frank Wall Street Reform and Consumer Protection Act.
Black
Lung Laws
Under
the Black Lung Benefits Act of 1977 and the Black Lung Benefits Reform Act of 1977, as amended in 1981, coal mine operators must
make payments of black lung benefits to current and former coal miners with black lung disease, some survivors of a miner who
dies from this disease, and to fund a trust fund for the payment of benefits and medical expenses to claimants who last worked
in the industry prior to January 1, 1970. To help fund these benefits, a tax is levied on production of $1.10 per ton for underground-mined
coal and $0.55 per ton for surface-mined coal, but not to exceed 4.4% of the applicable sales price. This excise tax does not
apply to coal that is exported outside of the United States. In 2017, we recorded approximately $3.0 million of expense related
to this excise tax.
The
Patient Protection and Affordable Care Act includes significant changes to the federal black lung program including an automatic
survivor benefit paid upon the death of a miner with an awarded black lung claim and establishes a rebuttable presumption with
regard to pneumoconiosis among miners with 15 or more years of coal mine employment that are totally disabled by a respiratory
condition. These changes could have a material impact on our costs expended in association with the federal black lung program.
We may also be liable under state laws for black lung claims that are covered through either insurance policies or state programs.
Workers’
Compensation
We
are required to compensate employees for work-related injuries under various state workers’ compensation laws. The states
in which we operate consider changes in workers’ compensation laws from time to time. Our costs will vary based on the number
of accidents that occur at our mines and other facilities, and our costs of addressing these claims. We are insured under the
Ohio State Workers Compensation Program for our operations in Ohio. Our remaining operations, including Central Appalachia and
the Western Bituminous region, are insured through Rockwood Casualty Insurance Company.
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, 2017, we had accrued approximately $18.7 million for the estimated
costs of reclamation and mine closing, including the cost of treating mine water discharge when necessary. In addition, states
from time to time have increased and may continue to increase their fees and taxes to fund reclamation of orphaned mine sites
and abandoned mine drainage control on a statewide basis.
After
a mine application is submitted, public notice or advertisement of the proposed permit action is required, which is followed by
a public comment period. It is not uncommon for a SMCRA mine permit application to take over two years to prepare and review,
depending on the size and complexity of the mine, and another two years or even longer for the permit to be issued. The variability
in time frame required to prepare the application and issue the permit can be attributed primarily to the various regulatory authorities’
discretion in the handling of comments and objections relating to the project received from the general public and other agencies.
Also, it is not uncommon for a permit to be delayed as a result of judicial challenges related to the specific permit or another
related company’s permit.
Federal
laws and regulations also provide that a mining permit or modification can be delayed, refused or revoked if owners of specific
percentages of ownership interests or controllers (i.e., officers and directors or other entities) of the applicant have, or are
affiliated with another entity that has outstanding violations of SMCRA or state or tribal programs authorized by SMCRA. This
condition is often referred to as being “permit blocked” under the federal Applicant Violator Systems, or AVS. Thus,
non-compliance with SMCRA can provide the bases to deny the issuance of new mining permits or modifications of existing mining
permits, although we know of no basis by which we would be (and we are not now) permit-blocked.
In
addition, a February 2014 decision by the U.S. District Court for the District of Columbia invalidated the Office of Surface Mining
Reclamation and Enforcement’s (“OSM”) 2008 Stream Buffer Zone Rule, which prohibited mining disturbances within
100 feet of streams, subject to various exemptions. In December 2016, the OSM published the final Stream Protection Rule, which,
among other things, would 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, 2017, we had approximately $37.5 million in surety bonds outstanding to secure the performance of our reclamation
obligations.
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 is now being challenged in court and the rule remains
in effect until further order of the D.C. Circuit. In April 2017, the D.C. Circuit agreed to EPA’s request to delay proceedings
while the EPA reviews the supplemental finding to determine whether it should be maintained, modified, or otherwise reconsidered.
Future implementation of the rules in unclear. It remains to be seen whether any power plants may reevaluate their decision to
retire, or whether plants that have already installed certain controls to comply with MATS will continue to operate them at all
times. Installation of additional emissions control technology and additional measures required under laws and regulations related
to air emissions will make it more costly to operate coal-fired power plants and possibly other facilities that consume coal and,
depending on the requirements of individual state implementation plans, or SIPs, could make coal a less attractive fuel alternative
in the planning and building of power plants in the future.
In
addition to the greenhouse gas (“GHG”) regulations discussed below, air emission control programs that affect our
operations, directly or indirectly, through impacts to coal-fired utilities and other manufacturing plants, include, but are not
limited to, the following:
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The
EPA’s Acid Rain Program, provided in Title IV of the CAA, regulates emissions of
sulfur dioxide from electric generating facilities. Sulfur dioxide is a by-product of
coal combustion. Affected facilities purchase or are otherwise allocated sulfur dioxide
emissions allowances, which must be surrendered annually in an amount equal to a facility’s
sulfur dioxide emissions in that year. Affected facilities may sell or trade excess allowances
to other facilities that require additional allowances to offset their sulfur dioxide
emissions. In addition to purchasing or trading for additional sulfur dioxide allowances,
affected power facilities can satisfy the requirements of the EPA’s Acid Rain Program
by switching to lower sulfur fuels, installing pollution control devices such as flue
gas desulfurization systems, or “scrubbers,” or by reducing electricity generating
levels.
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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.
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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.
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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.
In November 2017, EPA announced initial area designations for most counties with respect to the 2015 primary and secondary
NAAQS for ozone and promulgated these designations in a final rule effective January 2018. In December 2017, EPA indicated
the anticipated area designations for the portions of the country not already designated for the 2015 ozone standards. EPA
has announced its intention to make final designation determinations for these portions of the country in the spring of 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.
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In
June 2005, the EPA amended its regional haze program to improve visibility in national parks and wilderness areas. Affected
states were required to develop SIPs by December 2007 that, among other things, 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. Accordingly,
future implementation of these rules is unclear.
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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 CO
2
, 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.
At
the Federal level, EPA has taken a number of steps to regulate GHG emissions. For example, in August 2015, the EPA issued its
final Clean Power Plan (the “CPP”) rules that establish carbon pollution standards for power plants, called CO
2
emission performance rates. Judicial challenges led the U.S. Supreme Court to grant a stay of the implementation of the
CPP in February 2016. By its terms, this stay will remain in effect throughout the pendency of the appeals process. The Supreme
Court’s stay applies only to EPA’s regulations for CO
2
emissions from existing power plants and will not
affect EPA’s standards for new power plants. It is not yet clear how the courts will rule on the legality of the CPP. Additionally,
in October 2017 EPA proposed to repeal the CPP, although the final outcome of this action and the pending litigation regarding
the CPP is uncertain at this time. In connection with the proposed repeal, EPA issued an Advance Notice of Proposed Rulemaking
(“ANPRM”) in December 2017 regarding emission guidelines to limit GHG emissions from existing electricity utility
generating units. The ANPRM seeks comment regarding what the EPA should include in a potential new, existing-source regulation
under the Clean Air Act of GHG emissions from electric utility generating units that it may propose. If the effort to repeal the
rules is unsuccessful and the rules were upheld at the conclusion of the appellate process and were implemented in their current
form or if the ANPRM results in a different proposal to control GHG emissions from electric utility generating units, demand for
coal will likely be further decreased. The EPA also issued a final rule for new coal-fired power plants in August 2015, which
essentially set performance standards for coal-fired power plants that requires partial carbon capture and sequestration (“CCS”).
Additional legal challenges have been filed against the EPA’s rules for new power plants. The EPA’s GHG rules for
new and existing power plants, taken together, have the potential to severely reduce demand for coal. In addition, passage of
any comprehensive federal climate change and energy legislation could impact the demand for coal. Any reduction in the amount
of coal consumed by North American electric power generators could reduce the price of coal that we mine and sell, thereby reducing
our revenues and materially and adversely affecting our business and results of operations.
Many
states and regions have adopted greenhouse gas initiatives and certain governmental bodies have or are considering the imposition
of fees or taxes based on the emission of greenhouse gases by certain facilities, including coal-fired electric generating facilities.
For example, in 2005, ten northeastern states entered into the Regional Greenhouse Gas Initiative agreement (“RGGI”)
calling for implementation of a cap and trade program aimed at reducing carbon dioxide emissions from power plants in the participating
states. The members of RGGI have established in statute and/or regulation a carbon dioxide trading program. Auctions for carbon
dioxide allowances under the program began in September 2008. Though New Jersey withdrew from RGGI in 2011, since its inception,
several additional northeastern states and Canadian provinces have joined as participants or observers.
Following
the RGGI model, five Western states launched the Western Regional Climate Action Initiative to identify, evaluate and implement
collective and cooperative methods of reducing greenhouse gases in the region to 15% below 2005 levels by 2020. These states were
joined by two additional states and four Canadian provinces and became collectively known as the Western Climate Initiative Partners.
However, in November 2011, six states withdrew, leaving California and the four Canadian provinces as members. At a January 12,
2012 stakeholder meeting, this group confirmed a commitment and timetable to create the largest carbon market in North America
and provide a model to guide future efforts to establish national approaches in both Canada and the U.S. to reduce GHG emissions.
It is likely that these regional efforts will continue.
Many
coal-fired plants have already closed or announced plans to close and proposed new construction projects have also come under
additional scrutiny with respect to GHG emissions. There have been an increasing number of protests and challenges to the permitting
of new coal-fired power plants by environmental organizations and state regulators due to concerns related to greenhouse gas emissions.
Other state regulatory authorities have also rejected the construction of new coal-fueled power plants based on the uncertainty
surrounding the potential costs associated with GHG emissions from these plants under future laws limiting the emissions of carbon
dioxide. In addition, several permits issued to new coal-fired power plants without limits on GHG emissions have been appealed
to the EPA’s Environmental Appeals Board. In addition, over 30 states have adopted mandatory “renewable portfolio
standards,” which require electric utilities to obtain a certain percentage of their electric generation portfolio from
renewable resources by a certain date. These standards range generally from 10% to 30%, over time periods that generally extend
from the present until between 2020 and 2030. Other states may adopt similar requirements, and federal legislation is a possibility
in this area. To the extent these requirements affect our current and prospective customers; they may reduce the demand for coal-fired
power, and may affect long-term demand for our coal.
If
mandatory restrictions on CO
2
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 CO
2
emissions from new fossil
fuel-fired electric utility generating power plants. The EPA has designated partial carbon capture and sequestration as the best
system of emission reduction for newly constructed fossil fuel-fired steam generating units at power plants to employ to meet
the standard. However, widespread cost-effective deployment of CCS will occur only if the technology is commercially available
at economically competitive prices and supportive national policy frameworks are in place.
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 uncertainty exists surrounding the standard
for what constitutes jurisdictional waters and wetlands subject to the protections and requirements of the Clean Water Act. A
2015 rulemaking by EPA to revise the standard was stayed nationwide by the U.S. Court of Appeals for the Sixth Circuit and stayed
for certain primarily western states by a United States District Court in North Dakota. In January 2018, the Supreme Court determined
that the circuit courts do not have jurisdiction to hear challenges to the 2015 rule, removing the basis for the Sixth Circuit
to continue its nationwide stay. Additionally, EPA has promulgated a final rule that extends the applicability date of the 2015
rule for another two years in order to allow EPA to undertake a rulemaking on the question of what constitutes a water of the
United States. In the meantime, judicial challenges to the 2015 rulemaking are likely to continue to work their way through the
courts along with challenges to the recent rulemaking that extends the applicability date of the 2015 rule. For now, EPA and the
Corps will continue to apply the existing standard for what constitutes a water of the United States as determined by the Supreme
Court in the
Rapanos
case and post-
Rapanos
guidance. Should the 2015 rule take effect, or should a different rule
expanding the definition of what constitutes a water of the United States be promulgated 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.
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, though it defers a final Bevill
regulatory determination with respect to CCB that is disposed of in landfills or surface impoundments. Additionally, in December
2016, Congress passed the Water Infrastructure Improvements for the Nation Act, which provides for the establishment of state
and EPA permit programs for the control of coal combustion residuals and authorizes states to incorporate EPA’s final rule
for coal combustion residuals or develop other criteria that are at least as protective as the final rule. The costs of complying
with these new requirements may result in a material adverse effect on our business, financial condition or results of operations,
and could potentially increase our customers’ operating costs, thereby reducing their ability to purchase coal as a result.
In addition, contamination caused by the past disposal of CCB, including coal ash, can lead to material liability to our customers
under RCRA or other federal or state laws and potentially reduce the demand for coal.
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 635 full-time employees as of December 31, 2017. 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 public may read and copy any materials that we file with the SEC at the SEC’s Public
Reference Room at 100 F Street, N.E., Washington, D.C. 20549. The public may obtain information on the operation of the Public
Reference Room by calling the SEC at 1-800-SEC-0330. Additionally, the SEC’s website,
http://www.sec.gov,
contains
reports, proxy and information statements, and other information regarding issuers, including us, that file electronically with
the SEC.
Item
1A. Risk Factors.
In
addition to the factors discussed elsewhere in this report, including the financial statements and related notes, you should consider
carefully the risks and uncertainties described below. If any of these risks or uncertainties, as well as other risks and uncertainties
that are not currently known to us or that we currently believe are not material, were to occur, our business, financial condition
or results of operation could be materially adversely affected and you may lose all or a significant part of your investment.
Risks
Inherent in Our Business
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:
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the
liquidity of our common units;
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the
market price of our common units;
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our
ability to issue additional securities or obtain financing;
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the
number of institutional and other investors that will consider investing in our common units;
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the
number of market makers in our common units;
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the
availability of information concerning the trading prices and volume of our common units; and
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the
number of broker-dealers willing to execute trades in our common units.
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Further,
since our common units were delisted from the NYSE, we are no longer subject to the NYSE rules including rules requiring us to
meet certain corporate governance standards. Without required compliance of these corporate governance standards, investor interest
in our common units may decrease.
We
may not have sufficient cash to enable us to pay the minimum quarterly distribution on our common units following establishment
of cash reserves and payment of costs and expenses, including reimbursement of expenses to our general partner.
We
may not have sufficient cash each quarter to pay the full amount of our minimum quarterly distribution of $4.45 per unit, or $17.80
per unit per year, which will require us to have available cash of approximately $58.1 million per quarter, or $232.4 million
per year, based on the number of common and subordinated units outstanding as of December 31, 2017 and the general partner interest.
The amount of cash we can distribute on our common and subordinated units principally depends upon the amount of cash we generate
from our operations, which will fluctuate from quarter to quarter based on, among other things:
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the
amount of coal we are able to produce from our properties, which could be adversely affected by, among other things, operating
difficulties and unfavorable geologic conditions;
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the
price at which we are able to sell coal, which is affected by the supply of and demand for domestic and foreign coal;
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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;
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the
proximity to and capacity of transportation facilities;
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the
price and availability of alternative fuels;
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the
impact of future environmental and climate change regulations, including those impacting coal-fired power plants;
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the
level of worldwide energy and steel consumption;
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prevailing
economic and market conditions;
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difficulties
in collecting our receivables because of credit or financial problems of customers;
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the
effects of new or expanded health and safety regulations;
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domestic
and foreign governmental regulation, including changes in governmental regulation of the mining industry, the electric utility
industry or the steel industry;
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changes
in tax laws;
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weather
conditions; and
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force
majeure.
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We
may reduce or eliminate distributions at any time we determine that our cash reserves are insufficient or are otherwise required
to fund current or anticipated future operations, capital expenditures, acquisitions, growth or expansion projects, debt repayment
or other business needs. Beginning with the quarter ended September 30, 2014, distributions on our common units were below the
minimum level and, beginning with the quarter ended June 30, 2015, we suspended the quarterly distribution on our common units
altogether. Pursuant to our partnership agreement, our common units accrue arrearages every quarter when the distribution level
is below the minimum quarterly distribution level and our subordinated units do not accrue such arrearages. In the future, if
and as distributions are made for any quarter, the first priority is to pay the then minimum quarterly distribution to common
unitholders. Any additional distribution amounts paid at that time are then paid to common unitholders until previously unpaid
accumulated arrearage amounts have been paid in full. Thus, we have arrearages accumulating on our common units since the distribution
level has been below our minimum quarterly level of $4.45 per unit. In addition, we have not paid any distributions on our subordinated
units for any quarter after the quarter ended March 31, 2012. We may not have sufficient cash available for distributions on our
common or subordinated units in the future. Any further reduction in the amount of cash available for distributions could impact
our ability to pay any quarterly distribution on our common units. Moreover, we may not be able to increase distributions on our
common units if we are unable to pay the accumulated arrearages on our common units as well as the full minimum quarterly distribution
on our subordinated units.
A
decline in coal prices could adversely affect our results of operations and cash available for distribution to our unitholders.
Our
results of operations and the value of our coal reserves are significantly dependent upon the prices we receive for our coal as
well as our ability to improve productivity and control costs. Prices for coal tend to be cyclical; however, prices have become
more volatile and depressed as a result of oversupply in the marketplace. The prices we receive for coal depend upon factors beyond
our control, including:
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the
supply of domestic and foreign coal;
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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;
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the
price and availability of alternative fuels for electricity generation;
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the
proximity to, and capacity of, transportation facilities;
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domestic
and foreign governmental regulations, particularly those relating to the environment, climate change, health and safety;
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the
level of domestic and foreign taxes;
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weather
conditions;
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terrorist
attacks and the global and domestic repercussions from terrorist activities; and
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prevailing
economic conditions.
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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 had an impact on the coal industry generally and may continue to do so. The demand for electricity
and steel may remain at low levels or further decline if economic conditions remain weak. If these trends continue, we may not
be able to sell all of the coal we are capable of producing or sell our coal at prices comparable to recent years.
In
addition to competing with other coal producers, we compete generally with producers of other fuels, such as natural gas. A decline
in the price of natural gas has made natural gas more competitive against coal and resulted in utilities switching from coal to
natural gas. Sustained low natural gas prices may also cause utilities to phase out or close existing coal-fired power plants
or reduce or eliminate construction of any new coal-fired power plants, which could have a material adverse effect on demand and
prices received for our coal. A substantial or extended decline in the prices we receive for our coal supply contracts could materially
and adversely affect our results of operations.
We
performed a comprehensive review of our current coal mining operation as well as potential future development projects for the
year ended December 31, 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 has been recorded on the Asset impairment and related charges line
of the consolidated statements of operations and comprehensive income.
We
also performed a comprehensive review of our coal mining operations as well as potential future development projects to ascertain
any potential impairment losses for the year ended December 31, 2016. Based on the impairment analysis, we concluded that none
of the coal properties, mine development costs or other coal mining equipment and related facilities were impaired at December
31, 2016. However, for the year ended December 31, 2016, we recorded $2.6 million of asset impairment losses and related charges
associated with the 2015 sale of the Deane mining complex. Of the total $2.6 million non-cash impairment and other non-cash charges
incurred, approximately $2.0 million related to impairment of the note receivable that was recorded in 2015 relating to the sale
of the Deane mining complex. The additional $0.6 million impairment related to other non-recoverable items associated with the
sale of the Deane mining complex. The $2.6 million asset impairment charge/loss for the Deane mining complex is recorded on the
Asset impairment and related charges line of the consolidated statements of operations and comprehensive income.
We
could be negatively impacted by the competitiveness of the global markets in which we compete and declines in the market demand
for coal.
We
compete with coal producers in various regions of the United States and overseas for domestic and international sales. The domestic
demand for, and prices of, our coal primarily depend on coal consumption patterns of the domestic electric utility industry and
the domestic steel industry. Consumption by the domestic electric utility industry is affected by the demand for electricity,
environmental and other governmental regulations, technological developments and the price of competing coal and alternative fuel
sources, such as natural gas, nuclear, hydroelectric and wind power and other renewable energy sources. Consumption by the domestic
steel industry is primarily affected by economic growth and the demand for steel used in construction as well as appliances and
automobiles. The competitive environment for coal is impacted by a number of the largest markets in the world, including the United
States, China, Japan and India, where demand for both electricity and steel has supported prices for steam and metallurgical coal.
The economic stability of these markets has a significant effect on the demand for coal and the level of competition in supplying
these markets. The cost of ocean transportation and the value of the U.S. dollar in relation to foreign currencies significantly
impact the relative attractiveness of our coal as we compete on price with foreign coal producing sources. During the last several
years, the U.S. coal industry has experienced increased consolidation, which has contributed to the industry becoming more competitive.
Increased competition by coal producers or producers of alternate fuels could decrease the demand for, or pricing of, or both,
for our coal, adversely impacting our results of operations and cash available for distribution.
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 82% of our coal sales volume for the year ended December 31, 2017. The majority of our sales
of steam coal during this period were to electric utilities for use primarily as fuel for domestic electricity consumption. The
amount of coal consumed by the domestic electric utility industry is affected primarily by the overall demand for electricity,
environmental and other governmental regulations, and the price and availability of competing fuels for power plants such as nuclear,
natural gas and oil as well as alternative sources of energy. We compete generally with producers of other fuels, such as natural
gas and oil. A decline in price for these fuels could cause demand for coal to decrease and adversely affect the price of our
coal. For example, sustained low natural gas prices have led, in some instances, to decreased coal consumption by electricity-generating
utilities. If alternative energy sources, such as nuclear, hydroelectric, wind or solar, become more cost-competitive on an overall
basis, demand for coal could decrease and the price of coal could be materially and adversely affected. Further, legislation requiring,
subsidizing or providing tax benefit for the use of alternative energy sources and fuels, or legislation providing financing or
incentives to encourage continuing technological advances in this area, could further enable alternative energy sources to become
more competitive with coal. A decrease in coal consumption by the domestic electric utility industry could adversely affect the
price of coal, which could materially adversely affect our results of operations and cash available for distribution to our unitholders.
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 2015 that requires California’s state pension funds to divest investments in companies that generate
50% or more of their revenue from coal mining by July 2017. 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 in recent years have received national attention and have led
to responses at the state and federal levels that have resulted in increased regulatory scrutiny of coal mining operations, particularly
underground mining operations. More stringent state and federal mine safety laws and regulations have included increased sanctions
for non-compliance. Moreover, future workplace accidents are likely to result in more stringent enforcement and possibly the passage
of new laws and regulations.
Within
the last few years, the industry has seen enactment of the Federal Mine Improvement and New Emergency Response Act of 2006 (the
“MINER Act”), subsequent additional legislation and regulation imposing significant new safety initiatives and the
Dodd-Frank Act, which, among other things, imposes new mine safety information reporting requirements. The MINER Act significantly
amended the Federal Mine Safety and Health Act of 1977 (the “Mine Act”), imposing more extensive and stringent compliance
standards, increasing criminal penalties and establishing a maximum civil penalty for non-compliance, and expanding the scope
of federal oversight, inspection, and enforcement activities. Following the passage of the MINER Act, the U.S. Mine Safety and
Health Administration (“MSHA”) issued new or more stringent rules and policies on a variety of topics, including:
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sealing
off abandoned areas of underground coal mines;
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mine
safety equipment, training and emergency reporting requirements;
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substantially
increased civil penalties for regulatory violations;
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training
and availability of mine rescue teams;
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underground
“refuge alternatives” capable of sustaining trapped miners in the event of an emergency;
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flame-resistant
conveyor belt, fire prevention and detection, and use of air from the belt entry; and
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post-accident
two-way communications and electronic tracking systems.
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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.” For now, EPA and the Corps will continue
to apply the existing standard for what constitutes a water of the United States as determined by the Supreme Court in the
Rapanos
case and post-
Rapanos
guidance. Should the 2015 rule take effect, or should a different rule expanding the definition
of what constitutes a water of the United States be promulgated 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:
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unfavorable
geologic conditions, such as the thickness of the coal deposits and the amount of rock embedded in or overlying the coal deposit;
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inability
to acquire or maintain necessary permits or mining or surface rights;
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changes
in governmental regulation of the mining industry or the electric utility industry;
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adverse
weather conditions and natural disasters;
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accidental
mine water flooding;
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labor-related
interruptions;
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transportation
delays;
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mining
and processing equipment unavailability and failures and unexpected maintenance problems; and
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accidents,
including fire and explosions from methane.
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Any
of these conditions may increase the cost of mining and delay or halt production at particular mines for varying lengths of time,
which in turn could adversely affect our results of operations and cash available for distribution to our unitholders.
In
general, mining accidents present a risk of various potential liabilities depending on the nature of the accident, the location,
the proximity of employees or other persons to the accident scene and a range of other factors. Possible liabilities arising from
a mining accident include workmen’s compensation claims or civil lawsuits for workplace injuries, claims for personal injury
or property damage by people living or working nearby and fines and penalties including possible criminal enforcement against
us and certain of our employees. In addition, a significant accident that results in a mine shut-down could give rise to liabilities
for failure to meet the requirements of coal supply agreements especially if the counterparties dispute our invocation of the
force majeure provisions of those agreements. We maintain insurance coverage to mitigate the risks of certain of these liabilities,
including business interruption insurance, but those policies are subject to various exclusions and limitations and we cannot
assure you that we will receive coverage under those policies for any personal injury, property damage or business interruption
claims that may arise out of such an accident. Moreover, certain potential liabilities such as fines and penalties are not insurable
risks. Thus, a serious mine accident may result in material liabilities that adversely affect our results of operations and cash
available for distribution.
Fluctuations
in transportation costs or disruptions in transportation services could increase competition or impair our ability to supply coal
to our customers, which could adversely affect our results of operations and cash available for distribution to our unitholders.
Transportation
costs represent a significant portion of the total cost of coal for our customers and, as a result, the cost of transportation
is a critical factor in a customer’s purchasing decision. Increases in transportation costs could make coal a less competitive
energy source or could make our coal production less competitive than coal produced from other sources.
Significant
decreases in transportation costs could result in increased competition from coal producers in other regions. For instance, coordination
of the many eastern U.S. coal loading facilities, the large number of small shipments, the steeper average grades of the terrain
and a more unionized workforce are all issues that combine to make shipments originating in the eastern United States inherently
more expensive on a per-mile basis than shipments originating in the western United States. Historically, high coal transportation
rates from the western coal producing regions limited the use of western coal in certain eastern markets. The increased competition
could have an adverse effect on our results of operations and cash available for distribution to our unitholders.
We
depend primarily upon railroads, barges and trucks to deliver coal to our customers. Disruption of any of these services due to
weather-related problems, strikes, lockouts, accidents, mechanical difficulties and other events could temporarily impair our
ability to supply coal to our customers, which could adversely affect our results of operations and cash available for distribution
to our unitholders.
In
recent years, the states of Kentucky and West Virginia have increased enforcement of weight limits on coal trucks on their public
roads. It is possible that other states may modify their laws to limit truck weight limits. Such legislation and enforcement efforts
could result in shipment delays and increased costs. An increase in transportation costs could have an adverse effect on our ability
to increase or to maintain production and could adversely affect our results of operations and cash available for distribution.
A
shortage of skilled labor in the mining industry could reduce productivity and increase operating costs, which could adversely
affect our results of operations and cash available for distribution to our unitholders.
Efficient
coal mining using modern techniques and equipment requires skilled laborers. During periods of high demand for coal, the coal
industry has experienced a shortage of skilled labor as well as rising labor and benefit costs, due in large part to demographic
changes as existing miners retire at a faster rate than new miners are entering the workforce. If a shortage of experienced labor
should occur or coal producers are unable to train enough skilled laborers, there could be an adverse impact on labor productivity,
an increase in our costs and our ability to expand production may be limited. If coal prices decrease or our labor prices increase,
our results of operations and cash available for distribution to our unitholders could be adversely affected.
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:
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quality
of coal;
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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;
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the
percentage of coal in the ground ultimately recoverable;
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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;
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historical
production from the area compared with production from other similar producing areas;
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the
timing for the development of reserves; and
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assumptions
concerning equipment and productivity, future coal prices, operating costs, capital expenditures and development and reclamation
costs.
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For
these reasons, estimates of the quantities and qualities of the economically recoverable coal attributable to any particular group
of properties, classifications of coal reserves and non-reserve coal deposits based on risk of recovery, estimated cost of production
and estimates of net cash flows expected from particular reserves as prepared by different engineers or by the same engineers
at different times may vary materially due to changes in the above factors and assumptions. Actual production from identified
coal reserve and non-reserve coal deposit areas or properties and revenues and expenditures associated with our mining operations
may vary materially from estimates. Accordingly, these estimates may not reflect our actual coal reserves or non-reserve coal
deposits. Any inaccuracy in our estimates related to our coal reserves and non-reserve coal deposits could result in lower than
expected revenues and higher than expected costs, which could have a material adverse effect on our ability to make cash distributions.
We
invest in non-coal natural resource assets, which could result in a material adverse effect on our results of operations and cash
available for distribution to our unitholders.
Part
of our business strategy is to expand our operations through strategic acquisitions, which includes investing in non-coal natural
resources assets. Our executive officers do not have experience investing in or operating non-coal natural resources assets and
we may be unable to hire additional management with relevant expertise in operating such assets. Acquisitions of non-coal natural
resource assets could expose us to new and additional operating and regulatory risks, including commodity price risk, which could
result in a material adverse effect on our results of operations and cash available for distribution to our unitholders.
The
amount of estimated maintenance capital expenditures our general partner is required to deduct from operating surplus each quarter
could increase in the future, resulting in a decrease in available cash from operating surplus that could be distributed to our
unitholders.
Our
partnership agreement requires our general partner to deduct from operating surplus each quarter estimated maintenance capital
expenditures as opposed to actual maintenance capital expenditures in order to reduce disparities in operating surplus caused
by fluctuating maintenance capital expenditures, such as reserve replacement costs or refurbishment or replacement of mine equipment.
Our annual estimated maintenance capital expenditures for purposes of calculating operating surplus is based on our estimates
of the amounts of expenditures we will be required to make in the future to maintain our long-term operating capacity. Our partnership
agreement does not cap the amount of maintenance capital expenditures that our general partner may estimate. The amount of our
estimated maintenance capital expenditures may be more than our actual maintenance capital expenditures, which will reduce the
amount of available cash from operating surplus that we would otherwise have available for distribution to unitholders. The amount
of estimated maintenance capital expenditures deducted from operating surplus is subject to review and change by the board of
directors of our general partner at least once a year, with any change approved by the conflicts committee. In addition to estimated
maintenance capital expenditures, reimbursement of expenses incurred by our general partner and its affiliates will reduce the
amount of available cash from operating surplus that we would otherwise have available for distribution to our unitholders. Please
read “—Risks Inherent in an Investment in Us—Cost reimbursements due to our general partner and its affiliates
for services provided to us or on our behalf will reduce cash available for distribution to our unitholders. The amount and timing
of such reimbursements will be determined by our general partner.”
Existing
and future laws and regulations regulating the emission of sulfur dioxide and other compounds could affect coal consumers and
as a result reduce the demand for our coal. A reduction in demand for our coal could adversely affect our results of operations
and cash available for distribution to our unitholders.
Federal,
state and local laws and regulations extensively regulate the amount of sulfur dioxide, particulate matter, nitrogen oxides, mercury
and other compounds emitted into the air from electric power plants and other consumers of our coal. These laws and regulations
can require significant emission control expenditures, and various new and proposed laws and regulations may require further emission
reductions and associated emission control expenditures. A certain portion of our coal has a medium to high sulfur content, which
results in increased sulfur dioxide emissions when combusted and therefore the use of our coal imposes certain additional costs
on customers. Accordingly, these laws and regulations may affect demand and prices for our higher sulfur coal. Please read “Part
I, Item 1. Business—Regulation and Laws.”
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 CO
2
, 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 rules that establish
carbon pollution standards for power plants, called CO
2
emission performance rates. Judicial challenges led the U.S.
Supreme Court to grant a stay of the implementation of the CPP in February 2016. By its terms, this stay will remain in effect
throughout the pendency of the appeals process. The stay suspends the rule, including the requirement that states submit their
initial plans by September 2016. The Supreme Court’s stay applies only to EPA’s regulations for CO
2
emissions
from existing power plants and will not affect EPA’s standards for new power plants. It is not yet clear how the courts
will rule on the legality of the CPP. Additionally, in October 2017 EPA proposed to repeal the CPP, although the final outcome
of this action and the pending litigation regarding the CPP is uncertain at this time. In connection with the proposed repeal,
EPA issued an Advance Notice of Proposed Rulemaking (“ANPRM”) in December 2017 regarding emission guidelines to limit
GHG emissions from existing electricity utility generating units. The ANPRM seeks comment regarding what the EPA should include
in a potential new, existing-source regulation under the Clean Air Act of GHG emissions from electric utility generating units
that it may propose. If the effort to repeal the rules is unsuccessful and the rules were upheld at the conclusion of the appellate
process and were implemented in their current form, or if the ANPRM results in a different proposal to control GHG emissions from
electric utility generating units, 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 challenges have been filed against the EPA’s rules for new power
plants. The EPA’s GHG rules for new and existing power plants, taken together, have the potential to severely reduce demand
for coal. In addition, passage of any comprehensive federal climate change and energy legislation could impact the demand for
coal. Any reduction in the amount of coal consumed by North American electric power generators could reduce the price of coal
that we mine and sell, thereby reducing our revenues and materially and adversely affecting our business and results of operations.
Many
states and regions have adopted greenhouse gas initiatives and certain governmental bodies have or are considering the imposition
of fees or taxes based on the emission of greenhouse gases by certain facilities, including coal-fired electric generating facilities.
For example, in 2005, ten northeastern states entered into the Regional Greenhouse Gas Initiative agreement (the “RGGI”),
calling for implementation of a cap and trade program aimed at reducing carbon dioxide emissions from power plants in the participating
states. Following the RGGI model, several western states and Canadian provinces have confirmed a commitment and timetable to create
a carbon market in North America. It is likely that these regional efforts will continue.
Many
coal-fired plants have already closed or announced plans to close and proposed new construction projects have also come under
additional scrutiny with respect to GHG emissions. There have been an increasing number of protests and challenges to the permitting
of new coal-fired power plants by environmental organizations and state regulators due to concerns related to greenhouse gas emissions.
Other state regulatory authorities have also rejected the construction of new coal-fueled power plants based on the uncertainty
surrounding the potential costs associated with GHG emissions from these plants under future laws limiting the emissions of GHGs.
In addition, several permits issued to new coal-fired power plants without limits on GHG emissions have been appealed to the EPA’s
Environmental Appeals Board. In addition, over 30 states have adopted mandatory “renewable portfolio standards,” which
require electric utilities to obtain a certain percentage of their electric generation portfolio from renewable resources by a
certain date. These standards range generally from 10% to 30%, over time periods that generally extend from the present until
between 2020 and 2030. Other states may adopt similar requirements, and federal legislation is a possibility in this area. To
the extent these requirements affect our current and prospective customers; they may reduce the demand for coal-fired power, and
may affect long-term demand for our coal.
If
mandatory restrictions on carbon dioxide emissions are imposed, the ability to capture and store large volumes of carbon dioxide
emissions from coal-fired power plants may be a key mitigation technology to achieve emissions reductions while meeting projected
energy demands. A number of recent legislative and regulatory initiatives to encourage the development and use of CCS technology
have been proposed or enacted. For example, in October 2015, the EPA released a rule that established, for the first time, new
source performance standards under the federal Clean Air Act for CO
2
emissions from new fossil fuel-fired electric
utility generating power plants. The EPA has designated partial carbon capture and sequestration as the best system of emission
reduction for newly constructed fossil fuel-fired steam generating units at power plants to employ to meet the standard. However,
widespread cost-effective deployment of CCS will occur only if the technology is commercially available at economically competitive
prices and supportive national policy frameworks are in place.
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:
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lack of availability, higher expense or unreasonable terms of new surety bonds;
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the
ability of current and future surety bond issuers to increase required collateral; and
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the
exercise by third-party surety bond holders of their right to refuse to renew the surety bonds.
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We
maintain surety bonds with third parties for reclamation expenses and other miscellaneous obligations. It is possible that we
may in the future have difficulty maintaining our surety bonds for mine reclamation. Due to adverse economic conditions and the
volatility of the financial markets, surety bond providers may be less willing to provide us with surety bonds or maintain existing
surety bonds or may demand terms that are less favorable to us than the terms we currently receive. We may have greater difficulty
satisfying the liquidity requirements under our existing surety bond contracts. As of December 31, 2017, we had $37.5 million
in reclamation surety bonds, secured by $6.0 million in letters of credit outstanding under our LoC Facility. 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, 2017, we had sales commitments for approximately
100% of our estimated coal production (including purchased coal to supplement our production) for the year ending December 31,
2018. 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 32% in 2018, 34% in 2019, and 34% in 2020.
We derived approximately 86.9% of our total coal revenues from coal sales to our ten largest customers for the year ended December
31, 2017, with affiliates of our top three customers accounting for approximately 39.4% 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:
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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;
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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;
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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;
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we
may be more vulnerable to competitive pressures or a downturn in our business or the economy generally; and
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our
flexibility in responding to changing business and economic conditions may be limited.
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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, 2017 our current portion of long-term debt that will be funded from cash flows from operating
activities during 2018 was approximately $0.4 million. Our ability to service our indebtedness will depend upon, among other things,
our future financial and operating performance, which will be affected by prevailing economic conditions and financial, business,
regulatory and other factors, some of which are beyond our control. If our operating results are not sufficient to service our
current or future indebtedness, we will be forced to take actions such as reducing distributions, reducing or delaying our business
activities, acquisitions, investments and/or capital expenditures, selling assets, restructuring or refinancing our indebtedness,
or seeking additional equity capital or bankruptcy protection. We may not be able to affect any of these remedies on satisfactory
terms, or at all.
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:
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incur
additional indebtedness or guarantee other indebtedness;
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grant
liens;
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make
certain loans or investments;
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dispose
of assets outside the ordinary course of business, including the issuance and sale of capital stock of our subsidiaries;
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change
the line of business conducted by us or our subsidiaries;
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enter
into a merger, consolidation or make acquisitions; or
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make
distributions if an event of default occurs.
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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:
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failure
to pay principal, interest or any other amount when due;
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breach
of the representations or warranties in the credit agreement;
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failure
to comply with the covenants in the credit agreement;
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cross-default
to other indebtedness;
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bankruptcy
or insolvency;
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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
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a
change of control.
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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 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.”
Risks
Inherent in an Investment in Us
Royal
owns and controls our general partner. Our general partner has fiduciary duties to its owners, and the interests of its owners
may differ significantly from, or conflict with, the interests of our public common unitholders.
Royal
owns and controls our general partner. Please read “Part I, Item 1. Business—Recent Developments—Royal Energy
Resources, Inc. Acquisition.” 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:
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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;
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neither
our partnership agreement nor any other agreement requires Royal to pursue a business strategy that favors us;
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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;
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except
in limited circumstances, our general partner has the power and authority to conduct our business without unitholder approval;
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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;
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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;
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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;
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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;
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our
general partner determines which costs incurred by it and its affiliates are reimbursable by us;
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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;
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our
general partner intends to limit its liability regarding our contractual and other obligations;
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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;
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our
general partner controls the enforcement of obligations that it and its affiliates owe to us;
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our
general partner decides whether to retain separate counsel, accountants or others to perform services for us; and
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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.
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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. There are no limitations in our partnership agreement or our credit agreement on
our ability to issue additional units, including units ranking senior to the common units. The incurrence of additional commercial
borrowings or other debt to finance our growth strategy would result in increased interest expense, which, in turn, may impact
the available cash that we have to distribute to our unitholders.
Our
partnership agreement limits our general partner’s fiduciary duties to holders of our common and subordinated units.
Our
partnership agreement contains provisions that modify and reduce the fiduciary standards to which our general partner would otherwise
be held by state fiduciary duty law. For example, our partnership agreement permits our general partner to make a number of decisions
in its individual capacity, as opposed to in its capacity as our general partner, or otherwise free of fiduciary duties to us
and our unitholders. This entitles our general partner to consider only the interests and factors that it desires and relieves
it of any duty or obligation to give any consideration to any interest of, or factors affecting, us, our affiliates or our limited
partners. Examples of decisions that our general partner may make in its individual capacity include:
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how
to allocate business opportunities among us and its affiliates;
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whether
to exercise its limited call right;
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how
to exercise its voting rights with respect to the units it owns;
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whether
to exercise its registration rights;
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whether
to elect to reset target distribution levels; and
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whether
or not to consent to any merger or consolidation of the partnership or amendment to the partnership agreement.
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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:
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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;
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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;
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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
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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:
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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;
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(2)
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approved
by the vote of a majority of the outstanding common units, excluding any common units owned by our general partner and its
affiliates;
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(3)
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on
terms no less favorable to us than those generally being provided to or available from unrelated third parties; or
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(4)
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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.
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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 66
2
/
3
%
of all outstanding common and subordinated units voting together as a single class is required to remove our general partner.
As of March 16, 2018, Royal owned an aggregate of approximately 54% of our common and subordinated units. Also, if our general
partner is removed without cause during the subordination period and no units held by the holders of the subordinated units or
their affiliates are voted in favor of that removal, all remaining subordinated units will automatically be converted into common
units and any existing arrearages on the common units will be extinguished. Cause is narrowly defined in our partnership agreement
to mean that a court of competent jurisdiction has entered a final, non-appealable judgment finding our general partner liable
for actual fraud or willful or wanton misconduct in its capacity as our general partner. Cause does not include most cases of
charges of poor management of the business.
Our
general partner interest or the control of our general partner may be transferred to a third party without unitholder consent.
Our
general partner may transfer its general partner interest to a third party in a merger or in a sale of all or substantially all
of its assets without the consent of our unitholders. Furthermore, our partnership agreement does not restrict the ability of
the members of our general partner to transfer their respective membership interests in our general partner to a third party.
The new members of our general partner would then be in a position to replace the board of directors and executive officers of
our general partner with their own designees and thereby exert significant control over the decisions taken by the board of directors
and executive officers of our general partner. This effectively permits a “change of control” without the vote or
consent of the unitholders.
Our
general partner has a limited call right that may require unitholders to sell their common units at an undesirable time or price.
If
at any time our general partner and its affiliates own more than 80% of the common units, our general partner will have the right,
but not the obligation, which it may assign to any of its affiliates or to us, to acquire all, but not less than all, of the common
units held by unaffiliated persons at a price equal to the greater of (1) the average of the daily closing price of the common
units over the 20 trading days preceding the date three days before notice of exercise of the call right is first mailed and (2)
the highest per-unit price paid by our general partner or any of its affiliates for common units during the 90-day period preceding
the date such notice is first mailed. As a result, unitholders may be required to sell their common units at an undesirable time
or price and may not receive any return or a negative return on their investment. Unitholders may also incur a tax liability upon
a sale of their units. Our general partner is not obligated to obtain a fairness opinion regarding the value of the common units
to be repurchased by it upon exercise of the limited call right. There is no restriction in our partnership agreement that prevents
our general partner from issuing additional common units and exercising its call right. If our general partner exercised its limited
call right, the effect would be to take us private and, if the units were subsequently deregistered, we would no longer be subject
to the reporting requirements of the Securities Exchange Act of 1934 (the “Exchange Act”). As of March 16,
2018, Royal owned an aggregate of approximately 50.6% of our common units and approximately 92.6% 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:
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our
existing unitholders’ proportionate ownership interest in us will decrease;
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the
amount of cash available for distribution on each unit may decrease;
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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;
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the
ratio of taxable income to distributions may increase;
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the
relative voting strength of each previously outstanding unit may be diminished; and
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the
market price of the common units may decline.
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The
Series A preferred units are senior in right of distributions and liquidation and upon conversion, would result in the issuance
of additional common units in the future, which could result in substantial dilution of our common unitholders’ ownership
interests.
The
Series A preferred units are a new class of partnership interests that rank senior to our common units with respect to distribution
rights and rights upon liquidation. We are required to pay annual distributions on the Series A preferred units in an amount equal
to the greater of (i) 50% of CAM Mining free cash flow (which is defined in our partnership agreement as (i) the total revenue
of the our Central Appalachia business segment, minus (ii) the cost of operations (exclusive of depreciation, depletion and amortization)
for the our Central Appalachia business segment, minus (iii) an amount equal to $6.50, multiplied by the aggregate number of met
coal and steam coal tons sold by us from our Central Appalachia business segment) and (ii) an amount equal to the number of outstanding
Series A preferred units multiplied by $0.80. If we fail to pay the any or all of the distributions in respect of the Series A
preferred units, such deficiency will accrue until paid in full and we will not be permitted to pay any distributions on our partnership
interests that rank junior to the Series A preferred units, including our common units. The preferred units also rank senior to
the common units in right of liquidation, and will be entitled to receive a liquidation preference in any such case.
We
may convert the Series A preferred units into common units at any time on or after the time at which the amount of aggregate distributions
paid in respect of each Series A preferred unit exceeds $10.00 per unit. All unconverted Series A preferred units will convert
into common units on December 31, 2021. The number of common units issued in any conversion will be based on the volume-weighted
average closing price of the common units for 90 days preceding the date of conversion. Accordingly, the lower the trading price
of our common units over the 90 day measurement period, the greater the number of common units that will be issued upon conversion
of the preferred units, which would result in greater dilution to our existing common unitholders. Dilution has the following
effects on our common unitholders:
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an
existing unitholder’s proportionate ownership interest in us will decrease;
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the
amount of cash available for distribution on each unit may decrease;
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the
relative voting strength of each previously outstanding unit may be diminished; and
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the
market price of the common units may decline.
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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 16, 2018, we had 12,993,869 common units, 1,145,743 subordinated units and 1,500,000 Series A preferred units outstanding.
All of the subordinated units will convert into common units on a one-for-one basis at the end of the subordination period. On
March 21, 2016, we issued 6,000,000 common units to Royal in a private placement. In connection with this issuance, we entered
into a registration rights agreement with Royal which grants Royal piggyback registration rights under certain circumstances with
respect to these common units. In addition, under our partnership agreement, our general partner and its affiliates (including
Royal) have registration rights relating to the offer and sale of any units that they hold, subject to certain limitations. Sales
by Royal or other large holders of a substantial number of our common units in the public markets, or the perception that such
sales might occur, could have a material adverse effect on the price of our common units or could impair our ability to obtain
capital through an offering of equity securities.
Our
partnership agreement restricts the voting rights of unitholders owning 20% or more of our common units.
Our
partnership agreement restricts unitholders’ voting rights by providing that any units held by a person or group that owns
20% or more of any class of units then outstanding, other than our general partner and its affiliates, their transferees and persons
who acquired such units with the prior approval of the board of directors of our general partner, cannot vote on any matter.
Cost
reimbursements due to our general partner and its affiliates for services provided to us or on our behalf will reduce cash available
for distribution to our unitholders. The amount and timing of such reimbursements will be determined by our general partner.
Prior
to making any distribution on the common units, we will reimburse our general partner and its affiliates for all expenses they
incur and payments they make on our behalf. Our partnership agreement does not set a limit on the amount of expenses for which
our general partner and its affiliates may be reimbursed. These expenses include salary, bonus, incentive compensation and other
amounts paid to persons who perform services for us or on our behalf and expenses allocated to our general partner by its affiliates.
Our partnership agreement provides that our general partner will determine in good faith the expenses that are allocable to us.
The reimbursement of expenses and payment of fees, if any, to our general partner and its affiliates will reduce the amount of
available cash to pay cash distributions to our unitholders.
While
our partnership agreement requires us to distribute all of our available cash, our partnership agreement, including provisions
requiring us to make cash distributions contained therein, may be amended.
While
our partnership agreement requires us to distribute all of our available cash, our partnership agreement, including provisions
requiring us to make cash distributions contained therein, may be amended. Our partnership agreement generally may not be amended
during the subordination period without the approval of our public common unitholders. However, our partnership agreement can
be amended with the consent of our general partner and the approval of a majority of the outstanding common units (including common
units held by Royal) after the subordination period has ended. As of March 16, 2018, Royal owned approximately 50.6% of the outstanding
common units and 92.6% 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
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 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, we believe that we satisfy the qualifying income requirement and will be treated as a partnership.
We may, however, decide that it is in our best interest to be treated as a corporation for 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 unitholders would be substantially
reduced. Therefore, treatment of us as a corporation would materially reduce the after-tax return to our 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 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. Although there is no current legislative proposal, a prior legislative proposal would have
eliminated the qualifying income exception to the treatment of all publicly traded partnerships as corporations upon which we
rely for our treatment as a partnership for U.S. federal income tax purposes.
In
addition on January 24, 2017, final regulations regarding which activities give rise to qualifying income within the meaning of
Section 7704 of the Code (the “Final Regulations”) were published in the Federal Register. The Final Regulations are
effective as of January 19, 2017, and apply to taxable years beginning on or after January 19, 2017. We do not believe the Final
Regulations affect our ability to be treated as a partnership for U.S. federal income tax purposes.
However,
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 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 or
any other matter affecting us. 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 unitholders
and thus will be borne indirectly by our unitholders and our general partner. 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
unitholders are required to pay taxes on their share of our income even if they do not receive any cash distributions from us.
Our
unitholders are required to pay federal income taxes and, in some cases, state and local income taxes, on their share of our taxable
income, whether or not they receive cash distributions from us. Our unitholders may not receive cash distributions from us equal
to their share of our taxable income or even equal to the actual tax due with respect to that income.
We
anticipate engaging in transactions to reduce our indebtedness and manage our liquidity that generate taxable income (including
cancellation of indebtedness income) allocable to unitholders, and income tax liabilities arising therefrom may exceed the value
of your investment in us.
In
response to current market conditions, from time to time we may consider engaging in transactions to delever us and manage our
liquidity that would result in income and gain to our unitholders without a corresponding cash distribution. For example, we may
sell assets and use the proceeds to repay existing debt or fund capital expenditures, in which case, you would be allocated taxable
income and gain resulting from the sale without receiving a cash distribution. Further, we may pursue opportunities to reduce
our existing debt, such as debt exchanges, debt repurchases, or modifications and extinguishment of our existing debt that would
result in “cancellation of indebtedness income” (also referred to as “COD income”) being allocated to
our unitholders as ordinary taxable income. Unitholders may be allocated COD income, and income tax liabilities arising therefrom
may exceed the current value of your investment in us.
Entities
taxed as corporations may have net operating losses to offset COD income or may otherwise qualify for an exception to the recognition
of COD income, such as the bankruptcy or insolvency exceptions. As long as we are treated as a partnership, however, these exceptions
are not available to the partnership and are only available to a unitholder if the unitholder itself is insolvent or in bankruptcy.
As a result, these exceptions generally would not apply to prevent the taxation of COD income allocated to our unitholders. The
ultimate tax effect of any such income allocations will depend on the unitholder’s individual tax position, including, for
example, the availability of any suspended passive losses that may offset some portion of the allocable COD income. Unitholders
may, however, be allocated substantial amounts of ordinary income subject to taxation, without any ability to offset such allocated
income against any capital losses attributable to the unitholder’s ultimate disposition of its units. Unitholders are encouraged
to consult their tax advisors with respect to the consequences to them of COD income.
Tax
gain or loss on the disposition of our units could be more or less than expected.
If
you sell your units, you will recognize gain or loss equal to the difference between the amount realized and your tax basis in
those units. Because distributions in excess of your allocable share of our net taxable income decrease your tax basis in your
units, the amount, if any, of such prior excess distributions with respect to the units you sell will, in effect, become taxable
income to you if you sell such units at a price greater than your tax basis in those units, even if the price you receive is less
than your original cost. In addition, because the amount realized includes a unitholder’s share of our non-recourse liabilities,
if you sell your units, you may incur a tax liability in excess of the amount of cash you receive from the sale.
A
substantial portion of the amount realized from the sale of your units, whether or not representing gain, may be taxed as ordinary
income to you due to potential recapture items, including depreciation recapture. Thus, you may recognize both ordinary income
and capital loss from the sale of your units if the amount realized on a sale of your units is less than your adjusted basis in
the units.
Net
capital loss may only offset capital gains and, in the case of individuals, up to $3,000 of ordinary income per year. In the taxable
period in which you sell your units, you may recognize ordinary income from our allocations of income and gain to you prior to
the sale and from recapture items that generally cannot be offset by any capital loss recognized upon the sale of units.
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.
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, 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.
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.
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-U.S. Unitholder will be subject to withholding at the highest applicable effective tax rate and
a Non-U.S. 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
Tax Cuts and Jobs Act imposes a withholding obligation of 10% of the amount realized upon a Non-U.S. Unitholder’s sale or
exchange of an interest in a partnership that is engaged in a U.S. trade or business. However, due to challenges of administering
a withholding obligation applicable to open market trading and other complications, the IRS has temporarily suspended the application
of this withholding rule to open market transfers of interest in publicly traded partnerships pending promulgation of regulations
or other guidance that resolves the challenges. It is not clear if or when such regulations or other guidance will be issued.
If you are a non-U.S. person, you should consult your tax advisor before investing in our common units.
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.
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 units on the first day of each month, instead of on the basis of the date a particular unit is transferred.
The IRS may challenge this treatment, which could change the allocation of items of income, gain, loss and deduction among our
unitholders.
We
generally prorate our items of income, gain, loss and deduction between transferors and transferees of our common units each month
based upon the ownership of our units on the first day of each month (the “Allocation Date”), instead of on the basis
of the date a particular common unit is transferred. Similarly, we generally allocate gain or loss realized on the sale or other
disposition of our assets or, in the discretion of the general partner, any other extraordinary item of income, gain, loss or
deduction on the Allocation Date. Nonetheless, we allocate certain deductions for depreciation of capital additions based upon
the date the underlying property is placed in service. 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 unitholders.
A
unitholder whose units are the subject of a securities loan (e.g., a loan to a “short seller” to cover a short sale
of units) may be considered to have disposed of those units. If so, the unitholder would no longer be treated for tax purposes
as a partner with respect to those units during the period of the loan and could recognize gain or loss from the disposition.
Because
there are no specific rules governing the federal income tax consequences of loaning a partnership interest, a unitholder whose
units are the subject of a securities loan may be considered to have disposed of the loaned units. In that case, the unitholder
may no longer be treated for tax purposes as a partner in us with respect to those units during the period of the loan to the
short seller and the unitholder may recognize gain or loss from such disposition. Moreover, during the period of the loan, any
of our income, gain, loss or deduction with respect to those units may not be reportable by the unitholder and any cash distributions
received by the unitholder as to those units could be fully taxable as ordinary income. Unitholders desiring to assure their status
as partners and avoid the risk of gain recognition from a 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 units.
We
have adopted certain valuation methodologies in determining a unitholder’s allocations of income, gain, loss and deduction.
The IRS may challenge these methodologies or the resulting allocations, which could adversely affect the value of our common units.
In
determining the items of income, gain, loss and deduction allocable to our unitholders, we must routinely determine the fair market
value of our assets. Although we may, from time to time, consult with professional appraisers regarding valuation matters, we
make many fair market value estimates using a methodology based on the market value of our common units as a means to measure
the fair market value of our assets. The IRS may challenge these valuation methods and the resulting allocations of income, gain,
loss and deduction.
A
successful IRS challenge to these methods or allocations could adversely affect the timing or amount of taxable income or loss
being allocated to our unitholders. It also could affect the amount of gain from our unitholders’ sale of common units and
could have a negative impact on the value of the common units or result in audit adjustments to our unitholders’ tax returns
without the benefit of additional deductions.
Unitholders
will likely be subject to state and local taxes and return filing requirements in jurisdictions where they do not live as a result
of investing in our common units.
In
addition to U.S. federal income taxes, unitholders will likely be subject to other taxes, including state and local taxes, unincorporated
business taxes and estate, inheritance or intangible taxes that are imposed by the various jurisdictions in which we conduct business
or own property now or in the future, even if they do not live in any of those jurisdictions. Our unitholders will likely be required
to file state and local income tax returns and pay state and local income taxes in some or all of these various jurisdictions.
Further, unitholders may be subject to penalties for failure to comply with those requirements.
We
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. As we make acquisitions or expand
our business, we may own assets or conduct business in additional states that impose a personal income tax. It is your responsibility
to file all U.S. federal, state and local tax returns.